Annual Report — Form 10-K Filing Table of Contents
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phi10k-2008
2: EX-4.3 Pepco Supplemental Indenture Dated March 31, 2008 HTML 27K
14: EX-4.3 Courtesy Copy of Pepco Supplemental Indenture PDF 18K
Dated March 31, 2008 -- ex4-3
5: EX-10.10 Conectiv Supplemental Executive Retirement Plan HTML 115K
17: EX-10.10 Courtesy Copy of Conectiv Supplemental Executive PDF 68K
Retirement Plan -- ex10-10
6: EX-10.21 Non-Management Directors Compensation Plan HTML 32K
18: EX-10.21 Courtesy Copy of Non-Management Directors PDF 19K
Compensation Plan -- ex10-21
7: EX-10.22 Annual Executive Incentive Compensation Plan HTML 44K
19: EX-10.22 Courtesy Copy of Annual Executive Incentive PDF 32K
Compensation Plan -- ex10-22
8: EX-10.25 Change-In-Control Severance Plan HTML 72K
20: EX-10.25 Courtesy Copy of Change-In-Control Severance Plan PDF 50K
-- ex10-25
9: EX-10.28 Phi Combined Executive Retirement Plan HTML 70K
21: EX-10.28 Courtesy Copy of Phi Combined Executive Retirement PDF 55K
Plan -- ex10-28
10: EX-10.30 Phi Named Executive Officer 2009 Compensation HTML 29K
Determinations
22: EX-10.30 Courtesy Copy of Phi Named Executive Officer 2009 PDF 19K
Compensation Determinations -- ex10-30
11: EX-10.36 Amendment to Employment Agreement of W. T. HTML 21K
Torgerson
23: EX-10.36 Courtesy Copy of Amendment to Employment Agreement PDF 16K
of W. T. Torgerson -- ex10-36
12: EX-10.37 Credit Agreement Dated November 7, 2008 HTML 445K
24: EX-10.37 Courtesy Copy of Credit Agreement Dated November PDF 305K
7, 2008 -- ex10-37
3: EX-10.5 Phi Long-Term Incentive Plan HTML 102K
15: EX-10.5 Courtesy Copy of Phi Long-Term Incentive Plan -- PDF 65K
ex10-5
4: EX-10.6 Phi Executive and Director Deferred Compensation HTML 72K
Plan
16: EX-10.6 Courtesy Copy of Phi Executive and Director PDF 48K
Deferred Compensation Plan -- ex10-6
Securities
registered pursuant to Section 12(b) of the Act:
Registrant
Title
of Each Class
Name
of Each Exchange
on
Which
Registered
Pepco
Holdings
Common
Stock, $.01 par value
New
York Stock
Exchange
Securities
registered pursuant to Section 12(g) of the Act:
Registrant
Title
of Each Class
Pepco
Common
Stock, $.01 par value
DPL
Common
Stock, $2.25 par value
ACE
Common
Stock, $3.00 par value
Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.
Pepco
Holdings
Yes
X
No
Pepco
Yes
No
X
DPL
Yes
No
X
ACE
Yes
No
X
Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act.
Pepco
Holdings
Yes
No
X
Pepco
Yes
No
X
DPL
Yes
No
X
ACE
Yes
No
X
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d)
of the Securities Exchange Act of 1934 during the preceding 12 months and (2)
has been subject to such filing requirements for the past 90 days.
Pepco
Holdings
Yes
X
No
Pepco
Yes
X
No
DPL
Yes
X
No
ACE
Yes
X
No
Indicate by check mark if disclosure of
delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in the
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K (applicable to Pepco
Holdings only). X
Indicate by check mark whether the
registrant is a large accelerated filer, an accelerated filer or a
non-accelerated filer. See definition of “accelerated filer and
larger accelerated filer” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
Accelerated Filer
Non-Accelerated Filer
Pepco
Holdings
X
Pepco
X
DPL
X
ACE
X
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the
Act).
Pepco
Holdings
Yes
No
X
Pepco
Yes
No
X
DPL
Yes
No
X
ACE
Yes
No
X
Pepco, DPL, and ACE meet the
conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K
and are therefore filing this Form 10-K with the reduced disclosure format
specified in General Instruction I(2) of Form 10-K.
Registrant
Aggregate
Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates
of the Registrant at June 30, 2008
Number
of Shares of Common Stock of the Registrant Outstanding at
February 2, 2009
Pepco
Holdings
$5.2
billion
219,115,048
($.01
par value)
Pepco
None (a)
100
($.01
par value)
DPL
None (b)
1,000
($2.25
par value)
ACE
None
(b)
8,546,017
($3.00
par value)
(a)
All
voting and non-voting common equity is owned by Pepco
Holdings.
(b)
All
voting and non-voting common equity is owned by Conectiv, a wholly owned
subsidiary of Pepco Holdings.
THIS COMBINED FORM 10-K IS SEPARATELY
FILED BY PEPCO HOLDINGS, PEPCO, DPL AND ACE. INFORMATION CONTAINED
HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS
OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION
RELATING TO THE OTHER REGISTRANTS.
Portions of the Pepco Holdings, Inc.
definitive proxy statement for the 2009 Annual Meeting of Shareholders to be
filed with the Securities and Exchange Commission on or about March 26, 2009 are
incorporated by reference into Part III of this report.
TABLE
OF CONTENTS
Page
-
Glossary
of Terms
i
PART
I
Item
1.
-
Business
1
Item
1A.
-
Risk
Factors
21
Item
1B.
-
Unresolved
Staff Comments
31
Item
2.
-
Properties
32
Item
3.
-
Legal
Proceedings
33
Item
4.
-
Submission
of Matters to a Vote of Security Holders
34
PART
II
Item
5.
-
Market
for Registrant’s Common Equity, Related
Stockholder
Matters and Issuer Purchases of
Equity
Securities
35
Item
6.
-
Selected
Financial Data
38
Item
7.
-
Management’s
Discussion and Analysis of
Financial
Condition and Results of Operations
39
Item
7A.
-
Quantitative
and Qualitative Disclosures
About
Market Risk
140
Item
8.
-
Financial
Statements and Supplementary Data
145
Item
9.
-
Changes
in and Disagreements With Accountants
on
Accounting and Financial Disclosure
361
Item
9A.
-
Controls
and Procedures
361
Item
9A(T).
-
Controls
and Procedures
361
Item
9B.
-
Other
Information
363
PART
III
Item
10.
-
Directors,
Executive Officers and Corporate Governance
364
Item
11.
-
Executive
Compensation
366
Item
12.
-
Security
Ownership of Certain Beneficial Owners and
Management
and Related Stockholder Matters
367
Item
13.
-
Certain
Relationships and Related Transactions, and
Director
Independence
368
Item
14.
-
Principal
Accounting Fees and Services
368
PART
IV
Item
15.
-
Exhibits,
Financial Statement Schedules
369
Financial
Statements
Included
in Part II, Item 8
369
Schedule
I -
Condensed
Financial Information of Parent Company
370
Schedule
II
-
Valuation
and Qualifying Accounts
373
Exhibit
12
-
Statements
Re: Computation of Ratios
389
Exhibit
21
-
Subsidiaries
of the Registrant
393
Exhibit
23
-
Consents
of Independent Registered Public Accounting Firm
395
Exhibits
31.1 - 31.8
Rule
13a-14a/15d-14(a) Certifications
399
Exhibits
32.1 - 32.4
Section
1350 Certifications
407
Signatures
411
i
GLOSSARY
OF TERMS
Term
Definition
2007
Maryland Rate Orders
The
MPSC orders approving new electric service distribution base rates for
Pepco and DPL in Maryland, each effective June 16,2007.
A&N
A&N
Electric Cooperative, purchaser of DPL’s retail electric distribution
assets in Virginia
ABO
Accumulated
benefit obligation
ACE
Atlantic
City Electric Company
ACE
Funding
Atlantic
City Electric Transition Funding LLC
ADITC
Accumulated
deferred investment tax credits
AFUDC
Allowance
for Funds Used During Construction
AMI
Advanced
Metering Infrastructure
Ancillary
services
Generally,
electricity generation reserves and reliability
services
APIC
Additional
paid-in capital
APIC
pool
A
computation that establishes the beginning balance of the
APIC
Appeals
Office
The
Appeals Office of the IRS
Bankruptcy
Funds
$13 million
from the Bankruptcy Settlement to accomplish the remediation of the Metal
Bank/Cottman Avenue site
Bankruptcy
Settlement
The
bankruptcy settlement among the parties concerning the environmental
proceedings at the Metal Bank/Cottman Avenue site
BGS
Basic
Generation Service (the supply of electricity by ACE to retail customers
in New Jersey who have not elected to purchase electricity from a
competitive supplier)
BGS-FP
BGS-Fixed
Price service
BGS-CIEP
BGS-Commercial
and Industrial Energy Price service
Bondable
Transition Property
Right
to collect a non-bypassable transition bond charge from ACE customers
pursuant to bondable stranded costs rate orders issued by the
NJBPU
BSA
Bill
Stabilization Adjustment
CAA
Federal
Clean Air Act
CAIR
EPA’s
Clean Air Interstate rule
CAMR
EPA’s
Clean Air Mercury rule
CERCLA
Comprehensive
Environmental Response, Compensation, and Liability Act of
1980
Citgo
Citgo
Asphalt Refining Company
CO2
Carbon
dioxide
Conectiv
A
wholly owned subsidiary of PHI which is a holding company under PUHCA 2005
and the parent of DPL and ACE
Conectiv
Energy
Conectiv
Energy Holding Company and its subsidiaries
Conectiv
Group
Conectiv
and certain of its subsidiaries that were involved in a like-kind exchange
transaction under examination by the IRS
Cooling
Degree Days
Daily
difference in degrees by which the mean (high and low divided by 2) dry
bulb temperature is above a base of 65 degrees
Fahrenheit
CRMC
PHI’s
Corporate Risk Management Committee
CWA
Federal
Clean Water Act
D.
C. Circuit
United
States Court of Appeals for the District of Columbia
Circuit
DC
OPC
District
of Columbia Office of People’s Counsel
DCPSC
District
of Columbia Public Service Commission
ii
Term
Definition
Default
Electricity
Supply
The
supply of electricity by PHI’s electric utility subsidiaries at regulated
rates to retail customers who do not elect to purchase electricity from a
competitive supplier, and which, depending on the jurisdiction and period,
is also known as SOS or BGS service
Default
Supply Revenue
Revenue
received for Default Electricity Supply
Delaware
District Court
United
States District Court for the District of Delaware
Delta
Project
Conectiv
Energy’s 545 megawatt natural gas and oil-fired combined-cycle electricity
generation plant located in Peach Bottom Township,
Pennsylvania
DNREC
Delaware
Department of Natural Resources and Environmental
Control
DPL
Delmarva
Power & Light Company
DPSC
Delaware
Public Service Commission
DRP
PHI’s
Shareholder Dividend Reinvestment Plan
DSM
Demand
Side Management
EDIT
Excess
Deferred Income Taxes
EITF
Emerging
Issues Task Force
EPA
United
States Environmental Protection Agency
EPS
Earnings
per share
ERISA
Employee
Retirement Income Security Act of 1974
Exchange
Act
Securities
Exchange Act of 1934, as amended
FAS
Financial
Accounting Standards
FASB
Financial
Accounting Standards Board
FERC
Federal
Energy Regulatory Commission
FHACA
Flood
Hazard Area Control Act
FIFO
First
in first out
FIN
FASB
Interpretation Number
FPA
Federal
Power Act
FSP
FASB
Staff Position
FSP
AUG AIR-1
FSP
American Institute of Certified Public Accountants Industry Audit Guide,
Audits of Airlines — “Accounting for Planned Major Maintenance
Activities”
FWPA
Freshwater
Wetlands Protection Act
GAAP
Accounting
principles generally accepted in the United States of
America
GCR
Gas
Cost Recovery
GWh
Gigawatt
hour
Heating
Degree Days
Daily
difference in degrees by which the mean (high and low divided by 2) dry
bulb temperature is below a base of 65 degrees
Fahrenheit.
HEDD
High
electric demand day
HPS
Hourly
Priced Service DPL is obligated to provide to its largest
customers
IRC
Internal
Revenue Code
IRS
Internal
Revenue Service
ISO
Independent
system operator
ISONE
Independent
System Operator - New England
ITC
Investment
Tax Credit
LTIP
Pepco
Holdings’ Long-Term Incentive Plan
MAPP
Mid-Atlantic
Power Pathway
Maryland
OPC
Maryland
Office of People’s Counsel
Mcf
One
thousand cubic feet
Medicare
Act
Medicare
Prescription Drug, Improvement and Modernization Act of
2003
Mirant
Mirant
Corporation
MPSC
Maryland
Public Service Commission
NERC
North
American Electric Reliability
Corporation
iii
Term
Definition
NFA
No
Further Action letter issued by the NJDEP
NJBPU
New
Jersey Board of Public Utilities
NJDEP
New
Jersey Department of Environmental Protection
NJPDES
New
Jersey Pollutant Discharge Elimination System
Normalization
provisions
Sections
of the IRC and related regulations that dictate how excess deferred income
taxes resulting from the corporate income tax rate reduction enacted by
the Tax Reform Act of 1986 and accumulated deferred investment tax credits
should be treated for ratemaking purposes
NOx
Nitrogen
oxide
NPDES
National
Pollutant Discharge Elimination System
NUGs
Non-utility
generators
NYDEC
New
York Department of Environmental Conservation
ODEC
Old
Dominion Electric Cooperative, purchaser of DPL’s wholesale transmission
business in Virginia
Panda
Panda-Brandywine,
L.P.
Panda
PPA
PPA
between Pepco and Panda
PARS
Performance
Accelerated Restricted Stock
PBO
Projected
benefit obligation
PCI
Potomac
Capital Investment Corporation and its subsidiaries
Pepco
Potomac
Electric Power Company
Pepco
Energy Services
Pepco
Energy Services, Inc. and its subsidiaries
Pepco
Holdings or PHI
Pepco
Holdings, Inc.
PHI
Parties
The
PHI Retirement Plan, PHI and Conectiv, parties to cash balance plan
litigation brought by three management employees of PHI Service
Company
PHI
Retirement Plan
PHI’s
noncontributory retirement plan
PJM
PJM
Interconnection, LLC
Power
Delivery
PHI’s
Power Delivery Business
PPA
Power
Purchase Agreement
PRP
Potentially
responsible party
PUHCA
2005
Public
Utility Holding Company Act of 2005, which became effective February 8,2006
RAR
IRS
revenue agent’s report
RARM
Reasonable
Allowance for Retail Margin
RC
Cape May
RC
Cape May Holdings, LLC, an affiliate of Rockland Capital Energy
Investments, LLC, and the purchaser of the B.L. England generating
facility
RECs
Renewable
energy credits
Recoverable
stranded
costs
The
portion of stranded costs that is recoverable from ratepayers as approved
by regulatory authorities
Regulated
T&D Electric
Revenue
Revenue
from the transmission and the delivery of electricity to PHI’s customers
within its service territories at regulated rates
Revenue
Decoupling
Adjustment
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
RGGI
Regional
Greenhouse Gas Initiative
ROE
Return
on equity
RPM
Reliability
Pricing Model
SEC
Securities
and Exchange Commission
Sempra
Sempra
Energy Trading LLP
SFAS
Statement
of Financial Accounting Standards
SILO
Sale-in/lease-out
SNCR
Selective
Non-Catalytic Reduction
iv
Term
Definition
SO2
Sulfur
dioxide
SOS
Standard
Offer Service (the supply of electricity by Pepco in the District of
Columbia, by Pepco and DPL in Maryland and by DPL in Delaware on and after
May 1, 2006, to retail customers who have not elected to purchase
electricity from a competitive supplier)
Spark
spread
The
market price for electricity less the product of the cost of fuel times
the unit heat rate. It is used to estimate the relative
profitability of a generation unit.
SPCC
Spill
Prevention, Control, and Countermeasure plan required by
EPA
Spot
Commodities
market in which goods are sold for cash and delivered
immediately
Standard
Offer Service
revenue
or SOS revenue
Revenue
Pepco and DPL, respectively, receive for the procurement of energy for its
SOS customers
Starpower
Starpower
Communications, LLC
Stranded
costs
Costs
incurred by a utility in connection with providing service which would be
unrecoverable in a competitive or restructured market. Such
costs may include costs for generation assets, purchased power costs, and
regulatory assets and liabilities, such as accumulated deferred income
taxes.
T&D
Transmission
and distribution
Tolling
agreement
A
physical or financial contract where one party delivers fuel to a specific
generating station in exchange for the power output
Transition
Bond Charge
Revenue
ACE receives, and pays to ACE Funding, to fund the principal and interest
payments on Transition Bonds and related taxes, expenses and
fees
Transition
Bonds
Transition
bonds issued by ACE Funding
Treasury
lock
A
hedging transaction that allows a company to “lock-in” a specific interest
rate corresponding to the rate of a designated Treasury bond for a
determined period of time
VaR
Value
at Risk
VIE
Variable
interest entity
VRDBs
Variable
Rate Demand Bonds
v
THIS
PAGE LEFT INTENTIONALLY BLANK.
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:
·
The
distribution, transmission and default supply of electricity and the
delivery and supply of natural gas (Power Delivery), conducted through the
following regulated public utility
companies:
o
Potomac
Electric Power Company (Pepco), which was incorporated in Washington, D.C.
in 1896 and became a domestic Virginia corporation in
1949,
o
Delmarva
Power & Light Company (DPL), which was incorporated in Delaware in
1909 and became a domestic Virginia corporation in 1979,
and
o
Atlantic
City Electric Company (ACE), which was incorporated in New Jersey in
1924.
·
Competitive
energy generation, marketing and supply (Competitive Energy) conducted
through subsidiaries of Conectiv Energy Holding Company (collectively
Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries
(collectively Pepco Energy
Services).
The following chart shows, in
simplified form, the corporate structure of PHI and its principal
subsidiaries.
1
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, a subsidiary
service company of PHI, provides a variety of support services, including legal,
accounting, treasury, tax, purchasing and information technology services to PHI
and its operating subsidiaries. These services are provided pursuant
to a service agreement among PHI, PHI Service Company, and the participating
operating subsidiaries. The expenses of PHI Service Company are
charged to PHI and the participating operating subsidiaries in accordance with
costing methodologies set forth in the service agreement.
Pepco
Holdings’ management has identified its operating segments at December 31, 2008
as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other
Non-Regulated.For financial information relating to PHI’s segments, see Note
(5), “Segment Information” to the consolidated financial statements of PHI set
forth in Part II, Item 8. Each of Pepco, DPL and ACE has one
operating segment.
Investor
Information
Each of PHI, Pepco, DPL and ACE files
reports under the Securities Exchange Act of 1934, as amended. 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.
Power Delivery
The largest component of PHI’s business
is Power Delivery, which consists of the transmission, distribution and default
supply of electricity and the delivery and supply of natural gas. In
2008, 2007 and 2006, respectively, PHI’s Power Delivery operations produced 51%,
56%, and 61% of PHI’s consolidated operating revenues (including revenue from
intercompany transactions) and 72%, 66%, and 67% 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.
2
Delivery of Electricity, Natural Gas
and Default Electricity Supply
The Power Delivery business is
conducted by PHI’s three utility subsidiaries: Pepco, DPL and
ACE. Each company is responsible for the delivery of electricity and,
in the case of DPL, also natural gas in its service territory, for which it is
paid tariff rates established by the applicable local public service
commission. Each company also supplies electricity at regulated rates
to retail customers in its service territory who do not elect to purchase
electricity from a competitive energy supplier. The regulatory term
for this supply service varies by jurisdiction as follows:
Delaware
Standard
Offer Service (SOS)
District
of Columbia
SOS
Maryland
SOS
New
Jersey
Basic
Generation Service (BGS)
Effective January 2, 2008, DPL sold its
retail electric distribution assets and its wholesale electric transmission
assets in Virginia. This sale terminated DPL’s obligations as a
supplier of electricity to retail customers in its Virginia service territory
who do not elect to purchase electricity from a competitive
supplier.
In this Form 10-K, the supply service
obligations of the respective utility subsidiaries 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 provider of transmission service in the PJM
RTO region, which currently 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-approved rules, Pepco, DPL,
ACE and the other transmission-owning utilities in the region make their
transmission facilities available to the PJM RTO and PJM directs and controls
the operation of these transmission facilities. Transmission rates
are proposed by the transmission owner and
3
approved
by FERC. PJM provides billing and settlement services, collects
transmission service revenue from transmission service customers and distributes
the revenue to the transmission owners. PJM also directs the regional
transmission planning process within the PJM RTO region. The PJM
Board of Managers reviews and approves each PJM regional transmission expansion
plan.
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.
Seasonality
Power Delivery’s operating results
historically have been seasonal, generally producing higher revenue and income
in the warmest and coldest periods of the year. 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 in
2007 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 other reasons as a factor
having an impact on revenue and income.
Regulation
The retail operations of PHI’s utility
subsidiaries, including the rates they are permitted to charge customers for the
delivery and transmission of electricity and, in the case of DPL, also the
distribution and transportation of natural gas, are subject to regulation by
governmental agencies in the jurisdictions in which they provide utility service
as follows:
o
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).
o
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
4
its
Virginia assets on January 2, 2008, were regulated in Virginia by the
Virginia State Corporation Commission.
o
DPL’s
natural gas distribution and intrastate transportation operations in
Delaware are regulated by the DPSC.
o
ACE’s
electricity delivery operations are regulated by the New Jersey Board of
Public Utilities (NJBPU).
o
The
transmission and wholesale sale of electricity by each of PHI’s utility
subsidiaries are regulated by FERC.
o
The
interstate transportation and wholesale sale of natural gas by DPL is
regulated by FERC.
Pepco
Pepco is engaged in the transmission,
distribution and default supply of electricity in Washington, D.C. and major
portions of Prince George’s County and Montgomery County 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, 2008, Pepco delivered electricity to 767,000 customers (of which
247,000 were located in the District of Columbia and 520,000 were located in
Maryland), as compared to 760,000 customers as of December 31, 2007 (of which
241,800 were located in the District of Columbia and 518,200 were located in
Maryland).
In 2008, Pepco delivered a total of
26,863,000 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. 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.
Pepco has been providing market-based
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 2010. 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
also has an on-going obligation to provide SOS service, known as Hourly Priced
Service (HPS), for the largest customers. Power to supply the SOS HPS
customers is acquired in next-day and other short-term PJM RTO
markets. Pepco is entitled to recover from its SOS customers the cost
of the SOS supply plus an average margin of $.001651 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.
5
Pepco has been providing market-based
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
to residential and small and large commercial customers indefinitely, pending
investigation by the DCPSC of other alternatives, including the selection of
another party to administer the SOS franchise. 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 $.002151 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, 2008,
50% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to
SOS customers, as compared to 51% in 2007, and 33% of its District of Columbia
distribution sales were to SOS customers in 2008, as compared to 35% in
2007.
DPL
DPL is engaged in the transmission,
distribution and default supply of electricity in Delaware and portions of
Maryland. In northern Delaware, DPL also supplies and 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 Retail Electric Distribution and Wholesale
Transmission Assets,” DPL, on January 2, 2008, completed the sale of
substantially all of its Virginia retail electric distribution and wholesale
electric transmission assets.
DPL’s electricity distribution service
territory covers approximately 5,000 square miles and has a population of
approximately 1.3 million. As of December 31, 2008, DPL delivered
electricity to 498,000 customers (of which 299,000 were located in Delaware and
199,000 were located in Maryland), as compared to 519,000 electricity customers
as of December 31, 2007 (of which 298,000 were located in Delaware, 198,000
were located in Maryland, and 23,000 were located in Virginia).
In 2008, DPL delivered a total of
13,015,000 megawatt hours of electricity to its customers, of which 39% was
delivered to residential customers, 41% to commercial customers
6
and 20%
to industrial customers. In 2007, DPL delivered a total of 13,680,000
megawatt hours of electricity, of which 39% was delivered to residential
customers, 40% to commercial customers and 21% to industrial
customers.
DPL has been providing market-based 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 2012 and to medium, large
and general service commercial customers through May 2010. 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 SOS service, known as 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 approximately $3 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 distribution sales to
SOS customers represented 55% of total distribution sales (measured by megawatt
hours) for the year ended December 31, 2008, as compared to 54% in
2007.
DPL
has been providing market-based 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 2010. DPL
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. DPL also has an on-going
obligation to provide SOS service, known as HPS, for the largest
customers. Power to supply the SOS HPS customers is acquired in
next-day and other short-term PJM RTO markets. DPL 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. DPL is entitled to recover from its SOS
customers the costs of the SOS supply plus an average margin of $.001630 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. 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 distribution sales to
SOS customers represented 65% of total distribution sales (measured by megawatt
hours) for the year ended December 31, 2008, as compared to 67% in
2007.
7
DPL provided Default Service in
Virginia from March 2004 until the sale of its Virginia retail electric
distribution and wholesale transmission assets 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 distribution sales to
Default Service customers represented 94% of total distribution sales (measured
by megawatt hours) for the year ended December 31, 2007.
Sale
of Virginia Retail Electric Distribution and Wholesale Transmission
Assets
In
January 2008, DPL completed (i) the sale of its retail electric
distribution assets on the Eastern Shore of Virginia to A&N Electric
Cooperative and (ii) the sale of its wholesale electric transmission assets
located on the Eastern Shore of Virginia to Old Dominion Electric
Cooperative.
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. Intrastate transportation customers pay DPL
distribution service rates approved by the DPSC. DPL purchases
natural gas supplies for resale to its retail service customers from marketers
and producers through a combination of long-term agreements and next-day
delivery arrangements. For the twelve months ended December 31, 2008,
DPL supplied 65% of the natural gas that it delivered, compared to 67% in
2007.
DPL distributed natural gas to 122,000
customers as of December 31, 2008 and 2007. In 2008, DPL
distributed 20,300,000 Mcf (thousand cubic feet) of natural gas to customers in
its Delaware service territory, of which 38% were sales to residential
customers, 24% to commercial customers, 3% to industrial customers, and 35% to
customers receiving a transportation-only service. In 2007, DPL
delivered 20,700,000 Mcf of natural gas, of which 38% were sales to residential
customers, 25% were sales to commercial customers, 4% were to industrial
customers, and 33% were sales to customers receiving a transportation-only
service.
ACE
ACE is primarily engaged in the
transmission, distribution and default supply of electricity in a service
territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape
May, Cumberland and Salem counties in southern New Jersey. ACE’s
service territory covers approximately 2,700 square miles and has a population
of approximately 1.1 million. As of December 31, 2008, ACE
delivered electricity to 547,000 customers in its service territory, as compared
to 544,000 customers as of December 31, 2007. In 2008, ACE delivered
a total of 10,089,000 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 2007, ACE delivered a total of 10,187,000
megawatt hours of electricity to its customers, of which
8
44% was
delivered to residential customers, 44% to commercial customers, and 12% 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:
·
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 2,198 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.
·
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 33 megawatts, which
represents approximately 1% of ACE’s BGS load. This total load
is auctioned off each year for a one-year
term.
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 distribution sales to BGS customers
represented 78% of total distribution sales (measured by megawatt hours) for the
year ended December 31, 2008, as compared to 80% in 2007.
In February 2007, ACE completed the
sale of its B.L. England generating facility, which is reflected as discontinued
operations on ACE’s consolidated statements of earnings for the years ended
December 31, 2007 and 2006. ACE’s sale of its interests in the Keystone and
Conemaugh generating facilities in September 2006 is also reflected as
discontinued operations on the consolidated statement of earnings for the year
ended December 31, 2006 of ACE.
ACE has several contracts with
non-utility generators (NUGs) under which ACE purchased 3.8 million megawatt
hours of power in 2008. ACE sells the electricity purchased under the
contracts with NUGs into the wholesale market administered by PJM.
9
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
The Competitive Energy businesses
provide competitive generation, marketing and supply of electricity and natural
gas, and related energy management services primarily in the mid-Atlantic
region. These operations are conducted through subsidiaries of Conectiv Energy
and Pepco Energy Services. For the years ended December 31, 2008, 2007 and 2006,
PHI’s Competitive Energy operations produced 53%, 48%, and 43%, respectively, of
PHI’s consolidated operating revenues and 36%, 26%, and 20%, respectively, of
PHI’s consolidated operating income.
Conectiv
Energy
Conectiv Energy divides its activities
into two operational categories: (i) Merchant Generation & Load
Service and (ii) Energy Marketing.
Merchant Generation & Load
Service
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 the default electricity supply load shares of other
utilities within the PJM RTO and Independent System Operator - New England
wholesale markets. Conectiv Energy obtains the electricity required
to meet its Merchant Generation & Load Service power supply obligations from
its own generation plants, tolling agreements, bilateral contract purchases from
other wholesale market participants and purchases in the wholesale
market. Conectiv Energy’s primary fuel source for its generation
plants is natural gas. Conectiv Energy manages its natural gas supply
using a portfolio of long-term, firm storage and transportation contracts, and a
variety of derivative instruments.
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, 2008, Conectiv Energy owned and operated
mid-merit plants with a combined 2,778 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
10
Item 2
“Properties” of this Form 10-K. In addition to the generation plants
it owns, Conectiv Energy controls another 500 megawatts of capacity through
tolling agreements.
Conectiv Energy is constructing a 545
megawatt natural gas and oil-fired combined-cycle electricity generation plant
located in Peach Bottom Township, Pennsylvania known as the Delta
Project. 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 2011 through May 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.
Energy Marketing
Conectiv Energy also sells natural gas
and fuel oil to very large end-users and to wholesale market participants under
bilateral agreements. 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. In addition, Conectiv Energy 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 also engages in power origination
activities, which primarily represent the fixed margin component of structured
power transactions such as default supply service. Conectiv Energy
refers to these operations collectively as Energy Marketing.
Pepco Energy
Services
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., Texas and the Chicago,
Illinois areas. As of December 31, 2008, Pepco Energy Services’
estimated retail electricity backlog was approximately 33 million megawatts for
delivery through 2014, an increase of approximately 1 million megawatts over
December 31, 2007. Pepco Energy Services also sells natural gas to
customers located primarily in the mid-Atlantic region.
Pepco Energy Services also provides
energy savings performance contracting services principally to federal, state
and local government customers, owns and operates two district energy systems
and designs, constructs, and operates combined heat and power and central energy
plants.
Pepco Energy Services owns three
landfill gas-fired electricity plants that have a total generating capacity
rating of 10 megawatts and the output of these plants is sold into the wholesale
market administered by PJM and a solar photovoltaic plant that has a generating
capacity rating of 2 megawatts and the output of this plant is sold to its host
facility.
11
Pepco Energy Services provides high
voltage construction and maintenance services to customers throughout the United
States and low voltage electric construction and maintenance services and
streetlight construction and asset management services to utilities,
municipalities and other customers in the Washington, D.C. area.
Pepco Energy Services owns and operates
two oil-fired power plants. The power plants are located in
Washington, D.C. and have a generating capacity rating of approximately 790
megawatts. See Item 2 “Properties” of this Form
10-K. 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 megawatts. 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 and distribution 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.
Derivatives and Risk
Management
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 cash flows, and lock in favorable prices and margins when they become
available.
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
PHI’s Corporate Risk Management Committee 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” set forth in Part II of this Form
10-K.
PJM Capacity
Markets
A source of revenue for the Competitive
Energy businesses is the sale of capacity by Conectiv Energy and Pepco Energy
Services associated with their respective generating facilities. The
wholesale market for capacity in PJM 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
12
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 obligations. This capacity
can be obtained through the ownership of generation facilities, entry into
bilateral contracts or the purchase of capacity credits in the auctions
administered by PJM. All of the generating facilities owned by the 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 five auctions,
each covering capacity to be supplied over consecutive 12-month periods, with
the most recent auction covering the 12-month period beginning June 1,2011. 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 2012 through May 2013, will take place in May
2009. The Competitive Energy businesses are exposed to certain
deficiency charges payable to PJM if their generation units fail to meet certain
reliability levels. Some deficiency charges may be reduced by
purchasing capacity from PJM or third parties.
In addition to participating in the PJM
auctions, the 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.
Competition
The unregulated energy generation,
supply and marketing businesses located primarily 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 and quality of services offered to
customers.
Seasonality
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
13
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. The energy
management services of Pepco Energy Services generally are not
seasonal.
Other Business Operations
Through its subsidiary PCI, PHI
maintains a portfolio of cross-border energy sale-leaseback transactions, with a
book value at December 31, 2008 of approximately $1.3
billion. For additional information concerning these cross-border
lease transactions, see Note (16), “Commitments and Contingencies” to the
consolidated financial statements of PHI set forth in Item 8 “Financial
Statements and Supplementary Data” of the Form 10-K. This activity
constitutes a separate operating segment for financial reporting purposes, which
is designated “Other Non-Regulated.”
EMPLOYEES
At December 31, 2008, PHI had 5,474
employees, including 1,343 employed by Pepco, 898 employed by DPL, 523 employed
by ACE and 1,893 employed by PHI Service Company. The remaining were
employed by PHI’s Competitive Energy and other non-regulated
businesses. Approximately 2,896 employees (including 1,047 employed
by Pepco, 727 employed by DPL, 378 employed by ACE, 341 employed by PHI Service
Company, and 403 employed by the Competitive Energy businesses) 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 are expected to be approximately
$37 million in 2009 and $32 million in 2010. These expenditures
include $18 million and $11 million, respectively, to comply with
multi-pollutant regulations adopted by the Delaware Department of Natural
Resources and Environmental Control (DNREC), as more fully discussed
below. 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, rules and agency orders.
14
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
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 the 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 acquired,
as necessary, in the open market to maintain compliance with the regulatory
requirements during the calendar year and during the ozone season (May 1 to
September 30).
In 2005, the United States
Environmental Protection Agency (EPA) issued its Clean Air Interstate Rule
(CAIR), which imposes further 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 in 2010 for SO2. States
may implement CAIR by adopting EPA’s trading program or through regulations that
at a minimum achieve the level of 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. Generating units are permitted to
satisfy the CAIR requirements through the use of allocated allowances or
allowances acquired in the open market, through the installation of pollution
control devices or through fuel modifications.
In July 2008, the United States Court
of Appeals for the District of Columbia Circuit (the D.C. Circuit) vacated CAIR
and remanded the rule to the EPA for further rulemaking to address the flaws it
found with the rule, including EPA’s (1) failure to ensure that CAIR
emission reductions from upwind states would assist downwind states in meeting
air quality standards, (2) method for allocating SO2 and NOx
emission caps among the states and (3) efforts to terminate or limit acid
rain SO2
allowances. In December 2008, the D.C. Circuit held that CAIR
nevertheless would remain in effect pending such rulemaking.
The states in which PHI subsidiaries
own and operate generating units have either adopted regulations to implement
CAIR or will require compliance with the federal CAIR program. In
either case, the regulatory programs will require, beginning in 2009, the
surrender of one NOx annual allowance for each ton of NOx emitted during the
year and one NOx ozone season allowance for each ton of NOx emitted during the
ozone season; and between 2010 and
15
2014, the
surrender of one SO2 annual
allowance for each 0.5 ton of SO2 emitted
during the year and beginning in 2015, one SO2 allowance
for each 0.35 ton of SO2 emitted
during the year. To implement CAIR, the New Jersey Department of
Environmental Protection (NJDEP) adopted a new NOx trading program to replace
its prior NOx trading program. This new trading program allocates NOx
annual and NOx ozone season allowances to Conectiv Energy’s Carll’s Corner,
Cedar, Cumberland, Deepwater, Middle, Mickleton, and Sherman generating units,
and will operate in a manner similar to NJDEP’s prior 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
promulgated CAIR regulations in 2008 that are applicable to Conectiv Energy’s
Bethlehem generating units and the generating units being constructed in Peach
Bottom Township, Pennsylvania. Virginia is implementing CAIR by
participating in EPA’s cap and trade program making Conectiv Energy’s Tasley
peaking unit subject to federal CAIR for NOx and SO2. Conectiv
Energy’s Crisfield generating units in Maryland, Bayview units in Virginia, Edge
Moor 10, Delaware City 10 and West 10 units in Delaware, and Missouri Avenue
generating units in New Jersey produce fewer megawatts 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 are subject to CAIR
requirements. Pepco Energy Services’ Buzzard Point generating units
and its landfill gas generating units produce fewer megawatts than CAIR’s
applicability threshold and therefore are not subject to CAIR.
Conectiv Energy and Pepco Energy
Services units use NOx annual, NOx ozone season and SO2 allowances
allocated or acquired, as necessary, in the open market 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 financial results of
its business.
In August 2008, NJDEP proposed
amendments to its air pollution control regulations applicable to generating
units in New Jersey to implement a multi-pollutant strategy to reduce fine
particulate matter, SO2 and NOx
emissions from coal-fired boilers serving electric generating units and NOx
emissions from high electric demand day (HEDD) units, which are units capable of
generating 15 or more megawatts and which are operated less than or equal to an
average of 50 percent of the time during the ozone season. The units
that will be subject to NJDEP’s multi-pollutant regulations when promulgated
also are subject to CAIR requirements, and accordingly, must hold sufficient NOx
and SO2 allowances to cover their NOx and SO2
emissions. The proposed multi-pollutant regulations may require the
installation of pollution control equipment at the Deepwater generating station
in order to comply with the more stringent maximum allowable emission
rates. For the period 2009 through 2014, the proposed HEDD
regulations do not impose specific emission limits at any specific source, but
require reductions from HEDD units that Conectiv Energy chooses to operate in
accordance with a protocol submitted to NJDEP. Beginning in May 2015,
the proposed regulations establish specific maximum allowable emissions rates
for HEDD units. NJDEP’s regulations are expected to become final in
May 2009. Conectiv Energy is evaluating its options for complying
with the proposed regulations.
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
16
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 confirmed, based upon the monitoring of
mercury emissions at the Deepwater generating facility, that its only coal-fired
generating plant in New Jersey is in compliance with the mercury emissions limit
without the need for the installation of additional pollution control
equipment.
In November 2006, DNREC adopted
multi-pollutant 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 regulations establish stringent
short-term limits for emissions of NOx, SO2 and
mercury, and for Edge Moor’s residual oil-fired generating unit, impose more
stringent sulfur in fuel oil limits and establish stringent short-term limits
for NOx emissions. The regulations also cap annual mass 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. In December 2006, Conectiv Energy filed a complaint
with the Delaware Superior Court seeking review of the adoption of the new
regulations. In December 2008, Conectiv Energy reached a settlement
with DNREC. Under the terms of the settlement agreement, Conectiv
Energy will comply with the NOx, SO2 and
mercury emission reduction requirements by the regulatory compliance dates,
except that it will comply with the Phase II mercury emission limit by January1, 2012, which is one year earlier than the regulatory compliance
date. In addition, DNREC has agreed to increase the annual SO2 mass
emission limit as it relates to the Edge Moor residual oil-fired generating
unit. Conectiv Energy is installing new pollution control equipment
and/or enhancing existing equipment to comply with the multi-pollutant
regulations. Conectiv Energy currently estimates that it will cost up
to $81 million over a period of six years to install the control equipment
necessary to comply with the regulations. These estimated costs do
not include increased costs associated with operating control
equipment.
Conectiv Energy is installing water
injection pollution control equipment on its five stationary combustion turbines
in Delaware (Christiana 11 and 14, Edge Moor 10, Delaware City 10 and West 10)
to comply with new ozone season NOx emission limits. Conectiv Energy
estimates that the cost of compliance will be approximately
$3 million.
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
17
Columbia
Circuit determined that the delisting of coal- and oil-fired units from
regulation under CAA Section 112 was unlawful.
Carbon Dioxide Emissions
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), a cooperative effort by ten Northeast and mid-Atlantic states to first
stabilize and then beginning in 2015 incrementally reduce carbon dioxide
(CO2)
emissions with the goal of achieving an overall 10% reduction from baseline by
2018. Under RGGI, each of the participating states has adopted
legislation or regulations to implement a regional CO2 budget and
an allowance trading program to regulate emissions from fossil fuel-fired
electric generating units rated at 25 megawatts or greater. Under the
program each covered fossil fuel-fired electric generating unit is required,
commencing January 1, 2009, to hold allocated CO2
allowances, or and allowances acquired in the open market equivalent to its
CO2
emissions during specified compliance periods. Beginning in 2009, all
covered CO2 sources
must have an approved plan to monitor tons of CO2
emitted. The Maryland and New Jersey CO2 allowance
trading programs each provides for auction of substantially all of the
allowances allocated to the state by RGGI. Delaware’s program, in
2009, will auction 60% of allowances and allocate 40% of allowances to existing
CO2
sources. For each year after 2009, Delaware will increase the
percentage of allowances for auction by 8%, such that 100% of allowances will be
auctioned in 2014. The first compliance period is the three-year
period from 2009 to 2011. The period may be extended to four years if
a safety-valve mechanism is triggered by meeting certain market price
targets. In early 2012, each source will be required to surrender one
CO2
allowance for each ton of CO2 emitted
during the period. Conectiv Energy participated in the September and
December 2008 RGGI auctions and anticipates participating in subsequent RGGI
auctions as necessary.
In February 2007, the New Jersey
Governor signed an Executive Order that requires New Jersey to stabilize its
statewide greenhouse gas emissions at 1990 levels by 2020, and to reduce
statewide greenhouse gas emissions 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 statewide 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 statewide greenhouse gas emissions monitoring and reporting
program covering all sources within the state to evaluate progress toward the
2020 and 2050 greenhouse gas limits. These programs are in addition
to New Jersey’s participation in RGGI for electric generating
units.
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. Each
of
18
the steam
generating facilities operated by PHI’s subsidiaries has a NPDES permit
authorizing pollutant discharges, which is 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. In April
2008, the U.S. Supreme Court agreed to review the Riverkeeper II
decision. Briefing and oral argument before the Court have been
completed, but no decision has been rendered. Regardless of the
outcome of the pending judicial proceedings, additional EPA rulemaking is
expected, and the capital expenditures, if any, that may be needed as a
consequence of such new regulations will not be known until the rulemaking
process is concluded and 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, which administratively extended the existing permit. The
existing NJPDES permit for Deepwater requires 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 and any subsequent EPA rulemaking 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, NJDEP, at
Conectiv Energy’s request, has agreed to stay a cooling water intake structure
design upgrade requirement in Deepwater’s existing NJPDES
permit. NJDEP is preparing a renewal permit for Deepwater, which will
be published as a draft NJPDES renewal permit together with a request for public
comments.
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
19
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. 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. In June 2008, EPA issued a draft
permit. Pepco filed comments on the draft permit in January
2009. In February 2009, EPA issued the final draft permit and
initiated a 30-day public comment period, closing on March 16,2009. The capital expenditures, if any, that may be needed as a
consequence of new permit conditions, will not be known until the permit process
is concluded.
In November 2007, NJDEP adopted
amendments to the agency’s 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, which took
effect November 5, 2007, 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 filed an appeal of these regulations with the Appellate
Division of the Superior Court of New Jersey on November 3, 2008. PHI
cannot predict at this time the costs of complying with the FHACA regulations
due, among other things, to the potential for additional rulemaking as a result
of the appeal, as well as the possibility that NJDEP will issue exemptions from
the new regulations.
On October 6, 2008, NJDEP adopted
amendments to the agency’s regulations under the Freshwater Wetlands Protection
Act (FWPA). PHI believes that the amended FWPA regulations
unnecessarily restrict, among other things, various types of electric
transmission and distribution system maintenance and construction activity and
PHI is evaluating whether to appeal the FWPA regulations to the Appellate
Division of the Superior Court of New Jersey. PHI cannot predict at
this time the costs of complying with the amendments to the FWPA regulations due
to the potential for additional rulemaking if an appeal is filed, as well as the
possibility that NJDEP may issue exemptions from certain aspects of the new
regulations.
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 implement and amend Spill Prevention, Control, and
Countermeasure (SPCC) Plans. PHI facilities subject to the
regulations must now comply with these regulatory requirements by July 1,2009. In December 2008, EPA published a final rule to clarify its
regulations and streamline certain requirements. In a February 3,2009 Federal Register notice, EPA delayed until April 4, 2009 the effective date
of the December 2008 final rule and indicated that it is reviewing the dates by
which facilities must prepare or amend SPCC Plans and implement those
plans. PHI continues to analyze its facilities to identify equipment
and sites for which physical modifications may be necessary to reduce the risk
of a release of oil and comply with EPA’s SPCC regulations. As
provided in EPA’s regulations, SPCC Plans for PHI facilities for which the
installation of structures or equipment is not practicable include an oil spill
contingency plan and a written commitment of manpower, equipment and materials
to respond to a discharge of oil. PHI anticipates that compliance
with the EPA regulations will require physical modification of certain
facilities through the construction of containment
20
structures
or replacement of oil-filled equipment with non-oil-filled equipment at a total
anticipated cost to ACE, DPL and Pepco of approximately
$50 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 in pending
proceedings involving certain contaminated sites. See
(i) Item 7 “Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Capital Resources and Liquidity – Capital
Requirements – Environmental Remediation Obligations,” and (ii) Note (16),
“Commitments and Contingencies – Legal Proceedings – Environmental Litigation”
to the consolidated financial statements of PHI set forth in Part II, Item 8 of
this Form 10-K.
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.
The regulated utilities that
compose 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
21
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 “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
historically has been seasonal and weather patterns have had a material impact
on its operating performance. Demand for electricity is generally
higher in the summer months associated with cooling and demand for electricity
and natural gas is generally higher in the winter months associated with heating
as compared to other times of the year. Accordingly, each of PHI,
Pepco, DPL and ACE historically has generated less revenue and income when
temperatures are warmer than normal in the winter and cooler than normal in the
summer. In Maryland, the adoption in 2007 of a bill stabilization
adjustment mechanism for retail customers of Pepco and DPL, which decouples
distribution revenue for a given reporting period from the amount of power
delivered during the period, has had the effect of eliminating changes in the
use of electricity by such retail customers 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 energy management
services business of Pepco Energy Services is not seasonal.
22
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 of up to
two times the capacity payment that the generation facility
receives. Furthermore, the generation and transmission facilities of
the PHI companies that are defined as elements of the Bulk Electric System,
which is defined by the North American Electric Reliability Corporation (NERC)
as transmission facilities operating at a voltage of 100 kilovolts and above,
are subject to mandatory compliance with the reliability standards established
by the NERC and the Reliability First Regional Entity, which is the
NERC-designated regional entity with jurisdiction in the PJM
region. Failure to comply with the standards may result in
substantial monetary penalties and reflect poorly on the public image of
PHI.
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 provider of transmission
service in the PJM RTO region, which currently 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.
23
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 laws, 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 and effluent 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, in
addition to RGGI, 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 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,
24
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 on 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 on
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 the
Competitive Energy businesses.
Research and development activities are
ongoing to improve alternative technologies to produce electricity, including
fuel cells, wind energy, 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 the 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 the Competitive Energy businesses. Changes in
technology also could alter the channels through which retail electricity is
distributed to customers 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 commodity 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.
25
The
commodity hedging procedures used by the 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.
The
operations of the Competitive Energy businesses can give rise to significant
collateral requirements. The inability to fund those requirements may
prevent the businesses from hedging associated price risks or may require
curtailment of their operations. (PHI only)
A substantial portion of Pepco Energy
Services’ business is the sale of electricity and natural gas to retail
customers. In conducting this business Pepco Energy Services
typically enters into electricity and natural gas sale contracts under which it
is committed to supply the electricity or natural gas requirements of its retail
customers over a specified period at agreed upon prices. To acquire
this energy, Pepco Energy Services enters into wholesale purchase contracts for
electricity and natural gas. These contracts typically impose
collateral requirements on each party designed to protect the other party
against the risk of nonperformance between the date the contract is entered into
and the date the energy is paid for. The collateral required to be
posted can be of varying forms, including cash, letters of credit and
guarantees. When energy market prices decrease relative to the
supplier contract prices, Pepco Energy Service’s collateral
26
obligations
increase. In addition, Conectiv Energy and Pepco Energy Services each
enter into contracts to buy and sell electricity, various fuels, and related
products, including derivative instruments, to reduce its financial exposure to
changes in the value of its assets and obligations due to energy price
fluctuations. These contracts usually require the posting of
collateral. Under various contracts entered into by both businesses,
the required collateral is provided in the form of an investment grade guaranty
issued by PHI. Under these contracts, a reduction in PHI’s credit
rating can also trigger a requirement to post additional
collateral. To satisfy these obligations when required, PHI and its
non-utility subsidiaries rely primarily on cash balances, access to the capital
markets and existing credit facilities.
Particularly
in periods of energy market price volatility, the collateral obligations
associated with the Competitive Energy businesses can be substantial. These
collateral demands negatively affect PHI’s liquidity by requiring PHI to draw on
its capacity under its credit facilities and other financing
sources. The inability of PHI to maintain the necessary liquidity
also could have an adverse effect on PHI’s results of operations and financial
condition by requiring the Competitive Energy businesses to forego new business
opportunities, by requiring the businesses to curtail their hedging activity,
thereby increasing their exposure to energy market price changes or by rendering
them unable to meet their collateral obligations to counterparties.
PHI
and its subsidiaries have significant exposure to counterparty risk. (PHI
only)
Both
Conectiv Energy and Pepco Energy Services enter into transactions with numerous
counterparties. These include both commercial transactions for the
purchase and sale of electricity and natural gas and derivative and other
transactions to manage the risk of commodity price
fluctuations. Under these arrangements, the Competitive Energy
businesses are exposed to the risk that the counterparty may fail to perform its
obligation to make or take delivery under the contract, fail to make a required
payment or fail to return collateral posted by the Competitive Energy businesses
when no longer required. Under many of these contracts,
Conectiv Energy and Pepco Energy Services are entitled to receive collateral or
other types of performance assurance from the counterparty, which may be in the
form of cash, letters of credit or parent guarantees, to protect against
performance and credit risk. Even where collateral is provided,
capital market disruptions can prevent the counterparty from meeting its
collateral obligations or could degrade the value of letters of credit and
guarantees as a result of the lowered rating or insolvency of the issuer or
guarantor. In the event of a bankruptcy of a counterparty, bankruptcy
law, in some circumstances, could require Conectiv Energy and Pepco Energy
Services to surrender collateral held or payments received. In
addition, Conectiv Energy and Pepco Energy Services are participants in the
wholesale electric markets administered by various independent system operators
(ISOs), and in particular PJM. If an ISO incurs losses due to
counterparty nonperformance, those losses are allocated to and borne by other
market participants in the ISO. Such defaults could adversely affect
PHI’s results of operations, liquidity or financial condition. These
risks are increased during periods of significant commodity price fluctuations,
tightened credit and ratings downgrades.
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
27
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 the 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 eight cross-border energy lease investments, which as
of December 31, 2008, had an equity value of approximately $1.3 billion and from
which PHI currently derives approximately $56 million per year in tax benefits
in the form of interest and depreciation deductions in excess of rental
income. In 2005, the Treasury Department and IRS issued a notice
identifying sale-leaseback transactions with certain attributes entered into
with tax-indifferent parties as tax avoidance transactions, and the IRS
announced its intention to disallow the associated tax benefits claimed by the
investors in these transactions. PHI’s cross-border energy lease
investments, each of which is with a tax-indifferent party, have been under
examination by the IRS as part of the normal PHI federal income tax
audits. In connection with the audit of PHI’s 2001 and 2002 income
tax returns, the IRS disallowed the depreciation and interest deductions in
excess of rental income claimed by PHI with respect to six of its cross-border
energy lease investments. In addition, the IRS has sought to
recharacterize the leases as loan transactions as to which PHI would be subject
to original issue discount income.
PHI believes that its tax position with
regard to its cross-border energy lease investments is appropriate based on
applicable statutes, regulations and case law and is protesting the IRS
adjustments and the unresolved audit issues have been forwarded to the Appeals
Office of the IRS. In the event that PHI were not to prevail and were
to suffer a total disallowance of the tax benefits and incur imputed original
issue discount income due to the recharacterization of the leases as loans, as
of December 31, 2008, PHI would have been obligated to pay approximately $520
million in additional federal and state taxes and $83 million of
interest. In addition, the IRS could require PHI to pay a penalty of
up to 20% on the amount of additional taxes due. PHI
28
anticipates,
however that any additional taxes that it would be required to pay as
a result of the disallowance of prior deductions or a recharacterization of
leases as loans would be recoverable in the form of lower taxes over the
remaining term of the investments.
For further discussion of this matter
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” of this Form 10-K.
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 all rely on
access to both short-term money markets and long-term capital markets as sources
of liquidity and to satisfy their capital requirements that are not met by cash
flow from their operations. Capital market disruptions, or a
downgrade in their respective credit ratings, could increase the cost of
borrowing or could prevent the companies from accessing one or more financial
markets. Factors that could affect the ability of PHI and its
subsidiaries to access one or more financial markets could include, but are not
limited to:
· recession
or an economic slowdown;
· the
bankruptcy of one or more energy companies or financial
institutions;
· significant
changes in energy prices;
· 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.
The
funding of future defined benefit pension plan and post-retirement benefit plan
obligations is based on assumptions regarding the valuation of future benefit
obligations and the performance of plan assets. If market performance
decreases plan assets or changes in assumptions regarding the valuation of
benefit obligations increase our liabilities, PHI, Pepco, DPL or ACE may be
required to make significant unplanned cash contributions to fund these
plans.
PHI holds
assets in trust to meet its obligations under the PHI Retirement Plan (a defined
benefit pension plan) and its postretirement benefit plan. The
amounts that PHI is required to contribute (including the amounts for which
Pepco, DPL and ACE are responsible) to fund the trusts are determined based on
assumptions made as to the valuation of future benefit obligations, and the
investment performance of the plan assets. Accordingly, the
performance of the capital markets will affect the value of plan
assets. A decline in the market value of plan
29
assets
may increase the plan funding requirements to meet the future benefit
obligations. In addition, changes in interest rates affect the
valuation of the liabilities of the plans. As interest rates
decrease, the liabilities increase, potentially requiring additional
funding. Demographic changes, such as a change in the expected timing
of retirements or changes in life expectancy assumptions, also may increase the
funding requirements of the plans. A need for significant additional
funding of the plans could have a material adverse effect on the cash flow of
PHI, Pepco, DPL and ACE. Future increases in pension plan and other
post-retirement plan costs, to the extent they are not recoverable in the base
rates of PHI’s utility subsidiaries, could have a material adverse effect on
results of operations and financial condition of PHI, Pepco, DPL and
ACE.
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 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.
30
Because
Pepco is a wholly owned subsidiary of PHI, and each of DPL and ACE is an
indirect wholly owned subsidiary 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
None.
Pepco
None.
DPL
None.
ACE
None.
31
Item
2. PROPERTIES
Generation
Facilities
The following table identifies the
electric generating facilities owned by PHI’s subsidiaries at December 31,2008.
Electric Generating
Facilities
Location
Owner
Generating
Capacity (kilowatts)
Coal-Fired Units
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
1,000,000
Combustion Turbines/Combined Cycle
Units
Hay
Road Units 1-4
Wilmington,
DE
Conectiv
Energya
555,300
Hay
Road Units 5-8
Wilmington,
DE
Conectiv
Energya
565,000
Bethlehem
Units 1-8
Bethlehem,
PA
Conectiv
Energya
1,130,000
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
3,107,300
Landfill Gas-Fired Units
Fauquier
Landfill Project
Fauquier
County, VA
Pepco
Energy Servicesb
2,000
Eastern
Landfill Project
Baltimore
County, MD
Pepco
Energy Servicesd
3,000
Bethlehem
Landfill Project
Northampton,
PA
Pepco
Energy Servicesc
5,000
10,000
Solar Photovoltaic
Atlantic
City Convention Center
Atlantic
City, NJ
Pepco
Energy Servicese
2,000
Other Natural Gas Fired
Units
Deepwater
Unit 1
Pennsville,
NJ
Conectiv
Energya
78,000
Diesel Units
Crisfield
Crisfield,
MD
Conectiv
Energya
10,000
Bayview
Bayview,
VA
Conectiv
Energya
12,000
22,000
Total
Electric Generating Capacity
4,559,300
a
All
holdings of Conectiv Energy are owned by its various
subsidiaries.
b
These
facilities are owned by a subsidiary of Pepco Energy
Services.
c
This
facility is owned by Bethlehem Renewable Energy LLC, of which Pepco Energy
Services holds a 80% membership
interest.
d
This
facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy
Services holds a 75% membership
interest.
e
This
facility is owned by Pepco Energy Services,
Inc.
32
The
preceding table sets forth the net 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 December31, 2008, taking into account the sale by DPL of its Virginia retail electric
distribution and wholesale electric transmission assets in January 2008,
consisted of approximately 3,200 transmission circuit miles of overhead lines,
300 transmission circuit miles of underground cables, 18,200 distribution
circuit miles of overhead lines, and 15,500 distribution circuit miles of
underground cables, primarily in their respective service
territories. DPL and ACE own and operate distribution
system control centers in New Castle, Delaware and Mays Landing, New Jersey,
respectively. Pepco also operates a distribution system control
center in 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 approximately 3
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 255,500 Mcf per day. DPL also owns approximately
111 pipeline miles of natural gas transmission mains, 1,802 pipeline miles of
natural gas distribution mains, and 1,301 natural gas pipeline miles of service
lines. The natural gas transmission mains include approximately 7
miles of pipeline, 10% of which is owned and used by DPL for natural gas
operations, and 90% of which is owned and used by Conectiv Energy 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 (11), “Debt” to the
consolidated financial statements of PHI set forth in Item 8 of this Form
10-K.
Item
3. LEGAL
PROCEEDINGS
Pepco
Holdings
Other than litigation incidental to PHI
and its subsidiaries’ business, PHI is not a party to, and PHI and its
subsidiaries’ property is not subject to, any material pending legal proceedings
except as described in Note (16), “Commitments and Contingencies—Legal
Proceedings” to the consolidated financial statements of PHI set forth in Item 8
of this Form 10-K.
Pepco
Other than litigation incidental to its
business, Pepco is not a party to, and its property is not subject to, any
material pending legal proceedings except as described in Note (13),
“Commitments and Contingencies—Legal Proceedings” to the financial statements of
Pepco set forth in Item 8 of this Form 10-K.
33
DPL
Other than litigation incidental to its
business, DPL is not a party to, and its property is not subject to, any
material pending legal proceedings except as described in Note (14),
“Commitments and Contingencies—Legal Proceedings” to the financial statements of
DPL set forth in Item 8 of this Form 10-K.
ACE
Other than litigation incidental to its
business, ACE is not a party to, and its property is not subject to, any
material pending legal proceedings except as described in Note (14),
“Commitments and Contingencies—Legal Proceedings” to the financial statements of
ACE set forth in Item 8 of this Form 10-K.
Item
4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Pepco
Holdings
None.
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.
34
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
Price
Range
Per Share
High
Low
2008:
First
Quarter
$
.27
$
29.640
$
23.800
Second
Quarter
.27
27.385
24.010
Third
Quarter
.27
26.160
21.610
Fourth
Quarter
.27
23.930
15.270
$
1.08
2007:
First
Quarter
$
.26
$
29.280
$
24.890
Second
Quarter
.26
30.710
26.890
Third
Quarter
.26
29.280
24.200
Fourth
Quarter
.26
30.100
25.730
$
1.04
See Item 7, “Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Capital
Resources and Liquidity — Capital Requirements — Dividends” of this Form 10-K
for information regarding restrictions on the ability of PHI and its
subsidiaries to pay dividends.
At December 31, 2008, there were
approximately 61,347 holders of record of Pepco Holdings common
stock.
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.
35
Pepco
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.
Period
Aggregate
Dividends
2008:
First
Quarter
$
20,000,000
Second
Quarter
-
Third
Quarter
44,000,000
Fourth
Quarter
25,000,000
$
89,000,000
2007:
First
Quarter
$
15,000,000
Second
Quarter
14,000,000
Third
Quarter
45,000,000
Fourth
Quarter
12,000,000
$
86,000,000
DPL
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. Dividends received by Conectiv were used to pay down
short-term debt owed to PHI.
Period
Aggregate
Dividends
2008:
First
Quarter
$
27,000,000
Second
Quarter
15,000,000
Third
Quarter
-
Fourth
Quarter
10,000,000
$
52,000,000
2007:
First
Quarter
$
8,000,000
Second
Quarter
19,000,000
Third
Quarter
-
Fourth
Quarter
12,000,000
$
39,000,000
36
ACE
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. Dividends received by Conectiv were used to pay down short-term
debt owed to PHI.
Period
Aggregate
Dividends
2008:
First
Quarter
$
-
Second
Quarter
31,000,000
Third
Quarter
-
Fourth
Quarter
15,000,000
$
46,000,000
2007:
First
Quarter
$
20,000,000
Second
Quarter
10,000,000
Third
Quarter
20,000,000
Fourth
Quarter
-
$
50,000,000
Recent
Sales of Unregistered Equity Securities
Pepco
Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers.
Pepco
Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
37
Item
6 SELECTED FINANCIAL
DATA
PEPCO
HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
2008
2007
2006
2005
2004
(in
millions, except per share data)
Consolidated Operating
Results
Total
Operating Revenue
$
10,700
(a)
$
9,366
$
8,363
$
8,066
$
7,223
Total
Operating Expenses
9,932
8,560
(c)
7,670
(e)
7,160
(g)(h)(i)
6,451
Operating
Income
768
806
693
906
772
Other
Expenses
300
284
283
(f)
286
341
Preferred
Stock Dividend
Requirements
of Subsidiaries
-
-
1
3
3
Income
Before Income Tax Expense
and
Extraordinary Item
468
522
409
617
428
Income
Tax Expense
168
(a)(b)
188
(d)
161
255
(j)
167
(k)
Income
Before Extraordinary Item
300
334
248
362
261
Extraordinary
Item
-
-
-
9
-
Net
Income
300
334
248
371
261
Earnings
Available for
Common
Stock
300
334
248
371
261
Common Stock Information
Basic
Earnings Per Share of Common
Stock
Before Extraordinary Item
$
1.47
$
1.72
$
1.30
$
1.91
$
1.48
Basic
- Extraordinary Item Per
Share
of Common Stock
-
-
-
.05
-
Basic
Earnings Per Share
of
Common Stock
1.47
1.72
1.30
1.96
1.48
Diluted
Earnings Per Share
of
Common Stock Before
Extraordinary
Item
1.47
1.72
1.30
1.91
1.48
Diluted
- Extraordinary Item Per
Share
of Common Stock
-
-
-
.05
-
Diluted
Earnings Per Share
of
Common Stock
1.47
1.72
1.30
1.96
1.48
Cash
Dividends Per Share
of
Common Stock
1.08
1.04
1.04
1.00
1.00
Year-End
Stock Price
17.76
29.33
26.01
22.37
21.32
Net
Book Value per Common Share
19.14
20.04
18.82
18.88
17.74
Weighted
Average Shares Outstanding
204
194
191
189
177
Other Information
Investment
in Property, Plant
and
Equipment
$
12,926
$
12,307
$
11,820
$
11,441
$
11,109
Net
Investment in Property, Plant
and
Equipment
8,314
7,877
7,577
7,369
7,152
Total
Assets
16,475
15,111
14,244
14,039
13,375
Capitalization
Short-term
Debt
$
465
$
289
$
350
$
156
$
320
Long-term
Debt
4,859
4,175
3,769
4,203
4,362
Current
Maturities of Long-Term Debt
and
Project Funding
85
332
858
470
516
Transition
Bonds issued by ACE
Funding
401
434
464
494
523
Capital
Lease Obligations due within one year
6
6
6
5
5
Capital
Lease Obligations
99
105
111
117
122
Long-Term
Project Funding
19
21
23
26
65
Minority
Interest
6
6
24
46
55
Common
Shareholders’ Equity
4,190
4,018
3,612
3,584
3,339
Total
Capitalization
$
10,130
$
9,386
$
9,217
$
9,101
$
9,307
(a)
Includes
a pre-tax charge of $124 million ($86 million after-tax) related to the
adjustment to the equity value of cross-border energy lease investments,
and included in Income Taxes is a $7 million after-tax charge for the
additional interest accrued on the related tax
obligation.
(b)
Includes
$23 million of after-tax net interest income on uncertain and effectively
settled tax positions (primarily associated with the reversal of
previously accrued interest payable resulting from the final and tentative
settlements, respectively, with the IRS on the like-kind exchange and
mixed service cost issues and a claim made with the IRS related to the tax
reporting for fuel over- and under-recoveries) and a benefit of $8 million
(including a $3 million correction of prior period errors) related
to additional analysis of deferred tax balances completed in
2008.
(c)
Includes
$33 million ($20 million after-tax) from settlement of Mirant bankruptcy
claims.
(d)
Includes
$20 million ($18 million net of fees) benefit related to Maryland income
tax settlement.
(e)
Includes
$19 million of impairment losses ($14 million after-tax) related to
certain energy services business assets.
(f)
Includes
$12 million gain ($8 million after-tax) on the sale of Conectiv Energy’s
equity interest in a joint venture which owns a wood burning cogeneration
facility.
(g)
Includes
$68 million ($41 million after-tax) gain from sale of non-utility land
owned by Pepco at Buzzard Point.
(h)
Includes
$71 million ($42 million after-tax) gain (net of customer sharing) from
settlement of Mirant bankruptcy claims.
(i)
Includes
$13 million ($9 million after-tax) related to PCI’s liquidation of a
financial investment that was written off in 2001.
(j)
Includes
$11 million in income tax expense related to the mixed service cost issue
under IRS Revenue Ruling 2005-53.
(k)
Includes a $20
million charge related to an IRS settlement. Also includes $13
million tax benefit related to issuance of a local jurisdiction’s final
consolidated tax return
regulations.
38
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
41
Pepco
104
DPL
116
ACE
129
39
THIS
PAGE LEFT INTENTIONALLY BLANK.
40
PEPCO
HOLDINGS
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
PEPCO
HOLDINGS, INC.
GENERAL
OVERVIEW
In 2008, 2007 and 2006, respectively,
PHI’s Power Delivery operations produced 51%, 56%, and 61% of PHI’s consolidated
operating revenues (including revenues from intercompany transactions) and 72%,
66%, and 67% 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 electricity,
which for 2008, 2007, and 2006, was responsible for 94%, 94%, and 95%,
respectively, of Power Delivery’s operating revenues. The
distribution of natural gas contributed 6%, 6% and 5% of Power Delivery’s
operating revenues in 2008, 2007 and 2006, respectively. Power
Delivery represents one operating segment for financial reporting
purposes.
The Power Delivery business is
conducted by PHI’s three utility subsidiaries: Potomac Electric Power
Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City
Electric Company (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 applicable local public service
commission. Each company also supplies electricity at regulated rates
to retail customers in its service territory who do not elect to purchase
electricity from a competitive energy supplier. The regulatory term
for this supply service varies by jurisdiction as follows:
Delaware
Standard
Offer Service (SOS)
District
of Columbia
SOS
Maryland
SOS
New
Jersey
Basic
Generation Service (BGS)
Effective
January 2, 2008, DPL sold its retail electric distribution assets and its
wholesale electric transmission assets in Virginia. Prior to that
date, DPL supplied electricity at regulated rates to retail customers in its
service territory who did not elect to purchase electricity from a competitive
energy supplier, which is referred to in Virginia as Default
Service.
In this Form 10-K, the supply service
obligations of the respective utility subsidiaries 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.
41
PEPCO
HOLDINGS
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. The Power Delivery operating results historically have been
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.
In connection with its approval of new
electric service distribution base rates for Pepco and DPL in Maryland,
effective in June 2007 (the 2007 Maryland Rate Orders), the Maryland Public
Service Commission (MPSC) approved a bill stabilization adjustment mechanism
(BSA) for retail customers. 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
retail 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 from retail customers in Maryland to fluctuate from period
to period are changes in the number of customers and changes in the approved
distribution charge per customer.
The Competitive Energy businesses
provide 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), which
engage primarily in the generation and wholesale supply and marketing of
electricity and gas within the PJM Interconnection, LLC (PJM) and
Independent System Operator - New England (ISONE)
wholesale markets
·
Pepco
Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy
Services), which provides retail energy supply and energy services
primarily to commercial, industrial, and governmental
customers.
Each of Conectiv Energy and Pepco
Energy Services is a separate operating segment for financial reporting
purposes. For the years ended December 31, 2008, 2007 and 2006,
the operating
revenues of the Competitive Energy businesses (including revenue from
intercompany transactions) were equal to 53%, 48%, and 43%, respectively, of
PHI’s consolidated operating revenues, and the operating income of the
Competitive Energy businesses (including operating income from intercompany
transactions) was 36%, 26%, and 20% of PHI’s consolidated operating income for
the years ended December 31, 2008, 2007 and 2006,
respectively. For the years ended December 31, 2008, 2007 and 2006,
amounts equal to 7%, 10%, and 13% respectively, of the operating revenues of the
Competitive Energy businesses were attributable to electric energy and capacity,
and natural gas sold to the Power Delivery segment.
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.
42
PEPCO
HOLDINGS
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 businesses, like
the Power Delivery business, are 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, 2008 of
approximately $1.3 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 — PHI’s Cross-Border Energy
Lease Investments” in this Management’s Discussion and Analysis.
IMPACT
OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The
recent disruptions in the capital and credit markets, combined with the
volatility of energy prices, have had an impact on several aspects of PHI’s
businesses. While these conditions have required PHI and its
subsidiaries to make certain adjustments in their financial management
activities, PHI believes that it and its subsidiaries currently have sufficient
liquidity to fund their operations and meet their financial
obligations. These market conditions, should they continue, could
have a negative effect on PHI’s financial condition, results of operations and
cash flows.
Liquidity
Requirements
PHI and its subsidiaries depend on
access to the capital and credit markets to meet their liquidity and capital
requirements. To meet their liquidity requirements, PHI’s utility
subsidiaries and its Competitive Energy businesses historically have relied on
the issuance of commercial paper and short-term notes and on bank lines of
credit to supplement internally generated cash from operations. PHI’s
primary credit source is its $1.5 billion syndicated credit facility, which can
be used by PHI and its utility subsidiaries to borrow funds, obtain letters of
credit and support the issuance of commercial paper. This facility is
in effect until May 2012 and consists of commitments from 17 lenders, no one of
which is responsible for more than 8.5% of the total $1.5 billion
commitment. The terms and conditions of the facility are more fully
described below under the heading “Capital Resources and Liquidity ¾ Credit
Facilities.”
Due to the capital and credit market
disruptions, the market for commercial paper in the latter part of 2008 was
severely restricted for most companies. As a result, PHI and its
subsidiaries have not been able to issue commercial paper on a day-to-day basis
either in amounts or with maturities that they have typically required for cash
management purposes. To address the challenges posed by the current
capital and credit market environment and to ensure that PHI and its
subsidiaries will continue to have sufficient access to cash to meet their
liquidity needs, PHI and its subsidiaries have undertaken a number of actions,
including the following:
·
PHI
has conducted a review to identify cash and liquidity conservation
measures, including opportunities to reduce collateral obligations and to
defer capital expenditures due to lower than anticipated
growth. Several measures to
reduce
43
PEPCO
HOLDINGS
collateral
obligations and expenditures have been taken. Additional measures
could be undertaken if conditions warrant.
·
PHI
issued an additional 16.1 million shares of the Company’s common stock at
a price per share of $16.50 in November 2008, for net proceeds of $255
million.
·
PHI
added a 364-day $400 million credit facility in November
2008.
·
In
November 2008, ACE issued $250 million of First Mortgage Bonds, 7.75%
Series due November 15, 2018.
·
In
November 2008, DPL issued $250 million of First Mortgage Bonds, 6.40%
Series due December 1, 2013.
·
In
December 2008, Pepco issued $250 million of First Mortgage Bonds, 7.90%
Series due December 15, 2038.
At
December 31, 2008, the amount of cash, plus borrowing capacity under the
syndicated credit facility and PHI’s new 364-day credit facility, available to
meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of
which $843 million consisted of the combined cash and borrowing capacity of
PHI’s utility subsidiaries. During the months of January and February
2009, the average daily amount of the combined cash and borrowing capacity of
PHI on a consolidated basis was $1.4 billion, and of its utility subsidiaries
was $831 million. This decrease in liquidity of PHI on a consolidated
basis was primarily due to increased collateral requirements of the Competitive
Energy businesses. During the months of January and February 2009,
the combined cash and borrowing capacity of PHI’s utility subsidiaries ranged
from a low of $673 million to a high of $1 billion.
Collateral
Requirements of the Competitive Energy Businesses
In conducting its retail energy sales
business, Pepco Energy Services typically enters into electricity and natural
gas sales contracts under which it is committed to supply the electricity or
natural gas requirements of its retail customers over a specified period at
agreed upon prices. Generally, Pepco Energy Services acquires the
energy to serve this load by entering into wholesale purchase
contracts. To protect the respective parties against the risk of
nonperformance by the other party, these wholesale purchase contracts typically
impose collateral requirements that are tied to changes in the price of the
contract commodity. In periods of energy market price volatility,
these collateral obligations can fluctuate materially on a day-to-day
basis.
Pepco Energy Services’ practice of
offsetting its retail energy sale obligations with corresponding wholesale
purchases of energy has the effect of substantially reducing the exposure of its
margins to energy price fluctuations. In addition, the
non-performance risks associated with its retail energy sales are relatively low
due to the inclusion of governmental entities among its customers and the
purchase of insurance on a significant portion of its commercial and other
accounts receivable. However, because its retail energy sales
contracts typically do not have collateral obligations, during periods of
declining energy prices Pepco Energy Services is exposed to the asymmetrical
risk of having to post collateral under its
44
PEPCO
HOLDINGS
wholesale
purchase contracts without receiving a corresponding amount of collateral from
its retail customers. In the second half of 2008, the decrease in
energy prices has caused a significant increase in the collateral obligations of
Pepco Energy Services.
In addition, Conectiv Energy and Pepco
Energy Services in the ordinary course of business enter into various contracts
to buy and sell electricity, fuels and related products, including derivative
instruments, designed to reduce their financial exposure to changes in the value
of their assets and obligations due to energy price
fluctuations. These contracts also typically have collateral
requirements.
Depending on the contract terms, the
collateral required to be posted by Pepco Energy Services and Conectiv Energy
can be of varying forms, including cash and letters of credit. As of
December 31, 2008, the Competitive Energy businesses had posted net cash
collateral of $331 million and letters of credit of $558 million.
At
December 31, 2008, the amount of cash, plus borrowing capacity under the
syndicated credit facility and PHI’s new 364-day credit facility, available to
meet the liquidity needs of the Competitive Energy businesses on a consolidated
basis totaled $684 million. During the months of January and February
2009, the combined cash and borrowing capacity available to PHI’s Competitive
Energy businesses ranged from a low of $378 million to a high of $757
million.
Ongoing
Monitoring of Financial and Market Conditions
PHI monitors its liquidity position on
a daily basis and routinely conducts stress testing to assess the impact of
changes in commodity prices on its collateral requirements. Stress
testing conducted over the months of January and February 2009, based on
contractual rights and obligations in effect at the time, indicated that a 1%
change in forward prices corresponding to the periods under the various
contractual arrangements with respect to which collateral was required would
have caused an estimated change of approximately $6 million in Conectiv Energy’s
net collateral requirements and a change of approximately $17 million in Pepco
Energy Services’ net collateral requirements. PHI’s net collateral
obligations decrease when forward prices increase and increase when forward
prices decrease.
PHI also closely monitors its credit
ratings and outlooks and those of its rated subsidiaries, and computes the
hypothetical effect that changes in credit ratings would have on collateral
requirements and the cost of capital. Based on contractual provisions
in effect at December 31, 2008, a one-level downgrade in the unsecured debt
credit ratings of PHI and each of its rated subsidiaries, which would decrease
ratings to below “investment grade,” would increase the collateral obligations
of PHI and its subsidiaries by up to $462 million.
Counterparty
Credit Risk
PHI is exposed to the risk that the
counterparties to contracts may fail to meet their contractual payment
obligations or may fail to deliver purchased commodities or services at the
contracted price. PHI attempts to minimize these risks through, among other
things, formal credit policies, regular assessments of counterparty
creditworthiness, and the establishment of a credit limit for each
counterparty.
45
PEPCO
HOLDINGS
Pension
and Postretirement Benefit Plans
PHI and
its subsidiaries sponsor pension and postretirement benefit plans for their
employees. While the plans have not experienced any significant
impact in terms of liquidity or counterparty exposure due to the disruption of
the capital and credit markets, the stock market declines have caused a decrease
in the market value of benefit plan assets over the twelve months ended December31, 2008. The negative return did not have an impact on PHI’s results
of operations for 2008; however, this reduction in benefit plan assets will
result in increased pension and postretirement benefit costs in future
years.
PHI
currently estimates that its net periodic pension benefit cost will be
approximately $85 million in 2009, as compared to $24 million in 2008. The utility
subsidiaries are generally responsible for approximately 80% to 85% of the total
PHI net periodic pension benefit cost. Approximately 30% of net
periodic pension benefit cost is capitalized.
PHI
expects to make a discretionary tax deductible contribution to the pension plan
in 2009 of approximately $300 million. The utility subsidiaries will
be responsible for funding their share of the contribution of approximately $170
million for Pepco, $10 million for DPL and $60 million for ACE. PHI
Service Company is responsible to fund the remaining share of the
contribution. PHI will monitor the markets and evaluate any
additional discretionary funding needs later in the year. See Note
(10), “Pensions and Other Postretirement Benefits,” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K.
BUSINESS
STRATEGY
PHI’s business strategy is to remain a
mid-Atlantic 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 transmission
and distribution 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 within the
PJM Regional Transmission Organization (PJM RTO)
market.
·
Pursuing
technologies and practices that promote energy efficiency, energy
conservation and the reduction of greenhouse gas
emissions.
To further 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.
46
PEPCO
HOLDINGS
Strategic
Analysis of Pepco Energy Services’ Retail Energy Supply Business
Over the past several months, PHI has
been conducting a strategic analysis of the retail energy supply business of
Pepco Energy Services. This review has included, among other things, the
evaluation of potential alternative supply arrangements to reduce collateral
requirements or a possible restructuring, sale or wind down of the business.
As discussed above under the heading, “Impact of Current Capital and
Credit Market Disruption -- Collateral Requirements of the Competitive Energy
Businesses,” as energy prices have declined in the second half of 2008, the
collateral that Pepco Energy Services has been required to post to secure its
obligations under its wholesale energy purchase contracts has increased
substantially. Among the factors being considered is the return PHI
earns by investing capital in the retail energy supply business as compared to
alternative investments. PHI expects the retail energy supply
business to remain profitable based on its existing contract backlog and the
margins that have been locked in with corresponding wholesale energy purchase
contracts. The increased cost of capital associated with its collateral
obligations has been factored into its retail pricing and, as a consequence, PES
is experiencing reduced retail customer retention levels and reduced levels of
new retail customer acquisitions.
PHI’s net income for the year ended
December 31, 2008 was $300 million, or $1.47 per share, compared to $334
million, or $1.72 per share, for the year ended December 31, 2007.
Net
income for the year ended December 31, 2008, included the charges set forth
below in the Other Non-Regulated operating segment, which are presented net of
federal and state income taxes and are in millions of dollars:
Adjustment
to the equity value of cross-border energy lease investments to reflect
the impact of a change in assumptions regarding the estimated timing of
the tax benefits
$
(86)
Additional
interest accrued under Financial Accounting Standards Board Interpretation
No. 48 (FIN 48) related to the estimated federal and state income tax
obligations from the change in assumptions regarding the estimated timing
of the tax benefits on cross-border energy lease
investments
$
(7)
Net
income for the year ended December 31, 2007, included the credits set forth
below in the Power Delivery operating segment, which are presented net of
federal and state income taxes and are in millions of dollars.
Excluding the items listed above, net
income would have been $393 million, or $1.93 per share, in 2008 and $296
million, or $1.53 per share, in 2007.
47
PEPCO
HOLDINGS
PHI’s net
income for the years ended December 31, 2008 and 2007, by operating segment, is
set forth in the table below (in millions of dollars):
2008
2007
Change
Power
Delivery
$
250
$
232
$
18
Conectiv
Energy
122
73
49
Pepco
Energy Services
39
38
1
Other
Non-Regulated
(59)
46
(105)
Corp.
& Other
(52)
(55)
3
Total
PHI Net Income
$
300
$
334
$
(34)
Discussion
of Operating Segment Net Income Variances:
Power Delivery’s $18 million increase
in earnings is primarily due to the following:
·
$38
million increase due to the impact of the distribution base rate orders
($23 million related to Maryland, which became effective in June 2007 for
Pepco and DPL, and $15 million related to the District of Columbia, which
became effective in February 2008 for
Pepco).
·
$23
million increase due to favorable income tax adjustments primarily related
to FIN 48 interest impact.
·
$15
million increase due to FERC network transmission service rate changes in
June 2007 and 2008.
·
$20
million decrease due to the Mirant bankruptcy damage claims settlement in
2007.
·
$18
million decrease due to the Maryland tax settlement, net of fees in
2007.
·
$16
million decrease primarily due to lower sales (primarily decreased
customer usage, including an unfavorable impact of weather compared to
2007).
·
$5
million decrease due to higher operating and maintenance costs (primarily
higher employee-related costs and bad-debt
expense).
Conectiv Energy’s $49 million increase
in earnings is primarily due to the following:
·
$43
million increase in Merchant Generation & Load Service primarily due
to:
(i)
an
increase of $22 million primarily due to short-term sales of firm natural
gas and natural gas transportation and storage rights, the dual-fuel
capability of the combined cycle mid-merit units (fuel switching),
cross-commodity hedging (use of natural gas to hedge power positions), and
the opportunities created by the mid-merit combined cycle units’ operating
flexibility (option value) in conjunction with short-term power and fuel
price volatility,
(ii)
an
increase of $28 million due to higher PJM capacity prices net of capacity
hedges,
48
PEPCO
HOLDINGS
(iii)
an
increase of $11 million due to the application of fair value accounting
treatment and associated settlements with respect to excess coal hedges
accounted for at fair value,
(iv)
a
decrease of $9 million due to a lower of cost or market adjustment to the
value of oil inventory held at the power plants at year-end 2008,
and
(v)
a
decrease of $9 million due to lower sales of emissions
allowances.
·
$9
million increase in Energy Marketing primarily due to increased short-term
power desk margins, and new default electricity supply
contracts.
·
$5
million increase due to favorable income tax adjustments primarily due to
the reversal of FIN 48 interest
accruals.
·
$10
million decrease primarily due to higher plant
maintenance.
Pepco Energy Services’ $1 million
increase in earnings is primarily due to the following:
·
$6
million increase resulting from higher volumes due to growth in the retail
gas supply business.
·
$2
million increase in the retail electricity business due to more favorable
congestion costs; partially offset by higher cost of electricity and other
electricity supply costs.
·
$2
million increase resulting from favorable income tax adjustments related
to deferred income taxes.
·
$9
million decrease for the generation plants primarily due to Reliability
Pricing Model (RPM) related
charges.
Other Non-Regulated’s $105 million
decrease in earnings is primarily due to the following:
·
$86
million after-tax charge resulting from a $124 million adjustment to the
equity value of PHI’s cross-border energy lease
investments.
·
$7
million after-tax charge for interest accrued under FIN 48 related to
estimated federal and state income tax obligations for the period from
January 1, 2001 through June 30, 2008 resulting from the change in
assumptions regarding the estimated timing of the tax benefits of PHI’s
cross-border energy lease
investments.
·
$9
million decrease primarily due to favorable valuation adjustments to
certain other PCI portfolio investments in 2007; partially offset by lower
interest expense.
Corporate
and Other’s $3 million increase in earnings is primarily due to lower interest
expense and corporate governance costs.
49
PEPCO
HOLDINGS
CONSOLIDATED
RESULTS OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2008, to the year ended
December 31, 2007. 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:
2008
2007
Change
Power
Delivery
$
5,487
$
5,244
$
243
Conectiv
Energy
3,047
2,206
841
Pepco
Energy Services
2,648
2,309
339
Other
Non-Regulated
(60)
76
(136)
Corp.
& Other
(422)
(469)
47
Total
Operating Revenue
$
10,700
$
9,366
$
1,334
Power
Delivery
The following table categorizes Power
Delivery’s operating revenue by type of revenue.
2008
2007
Change
Regulated
T&D Electric Revenue
$
1,690
$
1,592
$
98
Default
Supply Revenue
3,413
3,295
118
Other
Electric Revenue
66
66
-
Total
Electric Operating Revenue
5,169
4,953
216
Regulated
Gas Revenue
204
211
(7)
Other
Gas Revenue
114
80
34
Total
Gas Operating Revenue
318
291
27
Total
Power Delivery Operating Revenue
$
5,487
$
5,244
$
243
Regulated
Transmission and Distribution (T&D) Electric Revenue includes revenue from
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. Regulated T&D Electric Revenue
also includes transmission service revenue that PHI’s utility subsidiaries
receive as transmission owners from PJM.
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
50
PEPCO
HOLDINGS
mutual
assistance to other utilities, highway relocation, rentals of pole attachments,
late payment fees, and collection fees.
Regulated Gas Revenue consists of
revenues from 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 sale of excess system
capacity.
In response to an order issued by the
New Jersey Board of Public Utilities (NJBPU) regarding changes to ACE’s retail
transmission rates, ACE has established deferred accounting treatment for the
difference between the rates that ACE is authorized to charge its customers for
the transmission of Default Electricity Supply and the cost that ACE
incurs. Under the deferral arrangement, any over or under recovery is
deferred as part of Deferred Electric Service Costs pending an adjustment of
retail rates in a future proceeding. As a consequence of the order,
effective January 1, 2008, ACE’s retail transmission revenue is being
recorded as Default Supply Revenue, rather than as Regulated T&D Electric
Revenue, thereby conforming to the practice of PHI’s other utility subsidiaries,
which previously established deferred accounting treatment for any over or under
recovery of retail transmission rates relative to the cost incurred. ACE’s
retail transmission revenue for the period prior to January 1, 2008 has
been reclassified to Default Supply Revenue in order to conform to the current
period presentation.
Electric Operating Revenue
Regulated
T&D Electric Revenue
2008
2007
Change
Residential
$
580
$
579
$
1
Commercial
746
720
26
Industrial
29
26
3
Other
335
267
68
Total
Regulated T&D Electric Revenue
$
1,690
$
1,592
$
98
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue, (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 Orders 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).
51
PEPCO
HOLDINGS
Regulated
T&D Electric Sales (Gigawatt hours (GWh))
2008
2007
Change
Residential
17,186
17,946
(760)
Commercial
28,739
29,137
(398)
Industrial
3,781
3,974
(193)
Other
261
261
-
Total
Regulated T&D Electric Sales
49,967
51,318
(1,351)
Regulated
T&D Electric Customers (in thousands)
2008
2007
Change
Residential
1,612
1,622
(10)
Commercial
196
197
(1)
Industrial
2
2
-
Other
2
2
-
Total
Regulated T&D Electric Customers
1,812
1,823
(11)
Due to
the sale of DPL’s Virginia retail electric distribution assets in
January 2008, the numbers of Regulated T&D Electric Customers listed
above include a decrease of approximately 19,000 residential customers and 3,000
commercial customers.
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, shopping 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 million primarily due to:
·
An
increase of $28 million due to a distribution rate change under the 2007
Maryland Rate Orders that became effective in June 2007, including a
positive $19 million Revenue Decoupling
Adjustment.
·
An
increase of $24 million due to a distribution rate change in the District
of Columbia that became effective in February
2008.
·
An
increase of $24 million due to a distribution rate change as part of a
higher New Jersey Societal Benefit Charge that became effective in June
2008 (substantially offset in Deferred Electric Service
Costs).
·
An
increase of $24 million in transmission service revenue primarily due to
transmission rate changes in June 2008 and
2007.
52
PEPCO
HOLDINGS
·
An
increase of $24 million 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.
·
An
increase of $4 million due to customer growth of 1% in 2008 (excluding
customers associated with the sale of DPL’s Virginia retail electric
distribution and wholesale transmission assets in January
2008).
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $20 million due to lower weather-related sales (a 2% decrease
in Heating Degree Days and a 10% decrease in Cooling Degree
Days).
·
A
decrease of $12 million due to the sale of DPL’s Virginia retail electric
distribution and wholesale transmission assets in January
2008.
Default Electricity Supply
Default
Supply Revenue
2008
2007
Change
Residential
$
1,882
$
1,843
$
39
Commercial
1,125
1,073
52
Industrial
75
94
(19)
Other
331
285
46
Total
Default Supply Revenue
$
3,413
$
3,295
$
118
Other Default Supply Revenue consists
primarily of revenue from the resale of energy and capacity purchased under
non-utility generating contracts (NUGs) in the PJM RTO market.
Default
Electricity Supply Sales (GWh)
2008
2007
Change
Residential
16,621
17,469
(848)
Commercial
9,564
9,910
(346)
Industrial
640
914
(274)
Other
101
131
(30)
Total
Default Electricity Supply Sales
26,926
28,424
(1,498)
Default
Electricity Supply Customers (in thousands)
2008
2007
Change
Residential
1,572
1,585
(13)
Commercial
166
166
-
Industrial
1
1
-
Other
2
2
-
Total
Default Electricity Supply Customers
1,741
1,754
(13)
53
PEPCO
HOLDINGS
Due to
the sale of DPL’s Virginia retail electric distribution assets in January 2008,
the number of Default Electricity Supply Customers listed above includes a
decrease of approximately 19,000 residential customers and 3,000 commercial
customers.
Default Supply Revenue, which is
substantially offset in Fuel and Purchased Energy and Other Services Cost of
Sales and Deferred Electric Service Costs, increased by $118 million primarily
due to:
·
An
increase of $202 million in market-based Default Electricity Supply
rates.
·
An
increase of $48 million in wholesale energy revenues due to the sale in
PJM RTO at higher market prices of electricity purchased from
NUGs.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $55 million due to lower weather-related sales (a 2% decrease
in Heating Degree Days and a 10% decrease in Cooling Degree
Days).
·
A
decrease of $33 million primarily due to existing commercial and
industrial customers electing to purchase electricity from competitive
suppliers.
·
A
decrease of $32 million due to the sale of DPL’s Virginia retail electric
distribution and wholesale transmission assets in January
2008.
·
A
decrease of $12 million due to differences in consumption among the
various customer rate classes.
Gas Operating Revenue
Regulated
Gas Revenue
2008
2007
Change
Residential
$
121
$
124
$
(3)
Commercial
69
73
(4)
Industrial
6
8
(2)
Transportation
and Other
8
6
2
Total
Regulated Gas Revenue
$
204
$
211
$
(7)
Regulated
Gas Sales (billion cubic feet)
2008
2007
Change
Residential
7
8
(1)
Commercial
5
5
-
Industrial
1
1
-
Transportation
and Other
7
7
-
Total
Regulated Gas Sales
20
21
(1)
54
PEPCO
HOLDINGS
Regulated
Gas Customers (in thousands)
2008
2007
Change
Residential
113
112
1
Commercial
9
10
(1)
Industrial
-
-
-
Transportation
and Other
-
-
-
Total
Regulated Gas Customers
122
122
-
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, shopping malls, stand alone
construction and tourism.
·
Industrial
activity in the region includes automotive, chemical and
pharmaceutical.
Regulated Gas Revenue decreased by $7
million primarily due to:
·
A
decrease of $4 million due to differences in consumption among the various
customer rate classes.
·
A
decrease of $3 million due to lower weather-related sales (a 3% decrease
in Heating Degree Days).
·
A
decrease of $2 million primarily due to Gas Cost Rate changes effective
April 2007, November 2007 and November
2008.
The
aggregate amount of these decreases was partially offset
by:
·
An
increase of $2 million due to a distribution base rate change effective
April 2007.
Other Gas Revenue
Other Gas Revenue, which is
substantially offset in Fuel and Purchased Energy and Other Services Cost of
Sales, increased by $34 million primarily due to revenue from higher off-system
sales, the result of an increase in market prices. Off-system sales
are made possible due to available pipeline capacity that results from low
demand for natural gas from regulated customers.
Conectiv
Energy
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.
55
PEPCO
HOLDINGS
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. Conectiv Energy also uses a number of and various types of
derivative contracts to lock in sales margins, and to economically hedge its
power and fuel purchases and sales. Gains and losses on derivative
contracts are netted in revenue and Cost of Sales as appropriate under the
applicable accounting rules. For these reasons, 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); natural gas transportation and storage; 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 power origination activities, which primarily represent the fixed margin
component of structured power transactions such as default supply
service.
Generation Fuel and Purchased
Power Expenses ($ millions) 3:
Generation
Fuel Expenses 4,5
Natural
Gas
$
223
$
268
$
(45)
Coal
57
62
(5)
Oil
46
34
12
Other6
2
2
-
Total
Generation Fuel Expenses
$
328
$
366
$
(38)
Purchased
Power Expenses 5
$
992
$
480
$
512
Statistics:
2008
2007
Change
Generation
Output (MWh):
Base-Load
7
1,710,916
2,232,499
(521,583)
Mid-Merit
(Combined Cycle) 8
2,625,668
3,341,716
(716,048)
Mid-Merit
(Other) 9
74,254
190,253
(115,999)
Peaking
78,450
146,486
(68,036)
Tolled
Generation
116,776
160,755
(43,979)
Total
4,606,064
6,071,709
(1,465,645)
Load
Service Volume (MWh) 10
10,629,905
7,075,743
3,554,162
Average
Power Sales Price
11($/MWh):
Generation
Sales 4
$
109.71
$
82.19
$
27.52
Non-Generation
Sales 12
$
92.02
$
70.43
$
21.59
Total
$
96.92
$
74.34
$
22.58
Average
on-peak spot power price at PJM East Hub ($/MWh) 13
$
91.73
$
77.85
$
13.88
Average
around-the-clock spot power price at PJM East Hub ($/MWh) 13
$
77.15
$
63.92
$
13.23
Average
spot natural gas price at market area M3 ($/MMBtu)14
$
9.83
$
7.76
$
2.07
Weather
(degree days at Philadelphia Airport): 15
Heating
degree days
4,403
4,560
(157)
Cooling
degree days
1,354
1,513
(159)
1
Includes
$397 million and $442 million of affiliate transactions for 2008 and 2007,
respectively.
2
Includes
$6 million and $7 million of affiliate transactions for 2008 and 2007,
respectively. Also, excludes depreciation and amortization
expense of $37 million and $38 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
emissions expenses, fuel additives, and other fuel-related
costs.
7
Edge
Moor Units 3 and 4 and Deepwater Unit
6.
8
Hay
Road and Bethlehem, all units.
9
Edge
Moor Unit 5 and Deepwater Unit 1.
10
Consists
of all default electricity supply sales; does not include standard product
hedge volumes.
11
Calculated
from data reported in Conectiv Energy’s Electric Quarterly Report (EQR)
filed with the FERC; does not include capacity or ancillary services
revenue.
12
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.
Source: Average
delivered natural gas price at Tetco Zone M3 as published in Gas
Daily.
15
Source:
National Oceanic and Atmospheric Administration National Weather Service
data.
57
PEPCO
HOLDINGS
Conectiv
Energy’s revenue and cost of sales are higher in 2008 primarily due to increased
default electricity supply volumes and higher energy commodity
prices. In 2008, Conectiv Energy expanded its default electricity
supply business into ISONE.
Conectiv Energy’s margins were
favorably impacted by higher energy commodity prices in the first half of 2008,
and unfavorably impacted by the decrease in prices and spark spreads during the
second half of the year. Volatile commodity prices contributed to
significant movements in the value of transactions accounted for at fair
value.
Merchant Generation & Load Service
gross margin increased approximately $73 million primarily due to:
·
An
increase of approximately $37 million primarily due to short-term sales of
firm natural gas, and natural gas transportation and storage rights, the
dual-fuel capability of the combined cycle mid-merit units (fuel
switching), cross-commodity hedging (use of natural gas to hedge power
positions), and the opportunities created by the mid-merit combined cycle
units’ operating flexibility (option value) in conjunction with short-term
power and fuel price volatility. This combination of strategies
positioned Conectiv Energy to realize the upside potential of its overall
portfolio during the winter period. The magnitude of gain was
due partly to significant fuel price increases in conjunction with less
significant increases in power
prices.
·
An
increase of approximately $46 million due to higher PJM capacity prices
net of capacity hedges.
·
An
increase of approximately $18 million due to the application of fair value
accounting treatment and associated settlements with respect to excess
coal hedges.
·
A
decrease of approximately $15 million due to a lower of cost or market
adjustment to the value of oil inventory held at the power plants at
year-end 2008.
·
A
decrease of approximately $15 million due to lower sales of emissions
allowances.
Energy
Marketing gross margin increased approximately $15 million primarily due
to:
·
An
increase of approximately $9 million in short-term power desk margins in
2008.
·
An
increase of approximately $9 million due to additional default electricity
supply contracts in 2008.
·
A
decrease of approximately $4 million due to lower wholesale gas
margins.
Pepco Energy
Services
Pepco
Energy Services’ operating revenue increased by $339 million to $2,648 million
in 2008 from $2,309 million in 2007 primarily due to:
58
PEPCO
HOLDINGS
·
An
increase of $259 million due to higher volumes of retail electric load
served due to customer acquisitions and higher prices in
2008,
·
An
increase of $64 million due to higher natural gas volumes driven by
customer acquisitions and higher prices in
2008,
·
An
increase of $26 million due to increased construction activities in
2008;
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $11 million due to RPM-related charges that lowered capacity
revenues for the generation plants.
Other
Non-regulated
Other Non-Regulated operating revenue
decreased by $136 million primarily due to:
·
A
non-cash charge of $124 million was recorded during 2008 as a result of
revised assumptions regarding the estimated timing of tax benefits from
PCI’s cross-border energy lease investments. In accordance with
Financial Accounting Standards Board Staff Position 13-2, this charge was
recorded as a reduction to lease revenue from these transactions, which is
included in Other Non-Regulated
revenues.
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:
2008
2007
Change
Power
Delivery
$
3,578
$
3,360
$
218
Conectiv
Energy
2,640
1,887
753
Pepco
Energy Services
2,489
2,161
328
Corp.
& Other
(418)
(465)
47
Total
$
8,289
$
6,943
$
1,346
Power
Delivery
Power
Delivery’s Fuel and Purchased Energy and Other Services Cost of Sales, which is
primarily associated with Default Electricity Supply sales, increased by $218
million primarily due to:
·
An
increase of $333 million in average energy costs, the result of new
Default Electricity Supply
contracts.
59
PEPCO
HOLDINGS
·
An
increase of $32 million in gas purchases for off-system sales, the result
of higher average gas costs.
·
An
increase of $24 million for energy and capacity purchased under the Panda
PPA.
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $61 million primarily due to commercial and industrial
customers electing to purchase electricity from competitive
suppliers.
·
A
decrease of $60 million due to lower weather-related
sales.
·
A
decrease of $45 million due to the sale of Virginia retail electric
distribution and wholesale transmission assets in January
2008.
Fuel and
Purchased Energy expense is substantially offset in Regulated T&D Electric
Revenue, Default Supply Revenue, Regulated Gas Revenue and Other Gas
Revenue.
Conectiv
Energy
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
Pepco
Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales
increased $328 million primarily due to:
·
An
increase of $236 million due to higher volumes of electricity purchased at
higher prices in 2008 to serve increased retail customer
load.
·
An
increase of $65 million due to higher volumes of natural gas purchased at
higher prices in 2008 to serve increased retail customer
load.
·
An
increase of $15 million due to increased construction activities in
2008.
·
An
increase of $12 million for the generation plants primarily due to
capacity costs related to RPM.
60
PEPCO
HOLDINGS
Other Operation and
Maintenance
A detail of PHI’s other operation and
maintenance expense is as follows:
2008
2007
Change
Power
Delivery
$
702
$
667
$
35
Conectiv
Energy
143
127
16
Pepco
Energy Services
87
74
13
Other
Non-Regulated
2
3
(1)
Corp.
& Other
(17)
(13)
(4)
Total
$
917
$
858
$
59
Other Operation and Maintenance
expenses of the Power Delivery segment increased by $35 million; however,
excluding $3 million resulting from the operation of ACE’s B.L. England electric
generating facility prior to its sale in February 2007, Other Operation and
Maintenance expenses increased by $38 million. The $38 million increase was
primarily due to:
·
An
increase of $17 million in deferred administrative expenses associated
with Default Electricity Supply (offset in Default Supply Revenue) due to
(i) the inclusion of $10 million of customer late payment fees in the
calculation of the deferral and (ii) a higher rate of recovery of bad debt
and administrative expenses as a result of an increase in Default
Electricity Supply revenue rates. See the discussion below
regarding a 2008 correction of errors in recording customer late payment
fees, including $6 million related to prior
periods.
·
An
increase of $11 million due to higher bad debt expenses associated with
distribution and Default Electricity Supply customers, of which
approximately $6 million was
deferred.
·
An
increase of $9 million in employee-related costs primarily due to the
recording of additional stock-based compensation expense as discussed
below, including $6 million related to prior
periods.
·
An
increase of $3 million in Demand Side Management program costs (offset in
Deferred Electric Service Costs).
·
An
increase of $3 million in legal
expenses.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $3 million in corrective and preventative maintenance and
emergency restoration costs.
·
A
decrease of $4 million in regulatory expenses primarily due to higher
expenses in 2007 relating to the District of Columbia distribution rate
case.
·
A
decrease of $3 million due to higher construction project write-offs in
2007 related to customer requested
work.
61
PEPCO
HOLDINGS
·
A
decrease of $2 million in accounting services related to tax consulting
fees.
Other Operation and Maintenance expense
for Conectiv Energy increased by $16 million primarily due to increased planned
maintenance at its power plants.
Other
Operation and Maintenance expense for Pepco Energy Services increased by $13
million due to increased compensation, benefit, outside contractor and
regulatory costs related to growth in its businesses.
During
2008, PHI recorded adjustments, on a consolidated basis, to correct errors
in Other Operation and Maintenance expenses for prior periods dating back to
February 2005 during which (i) customer late payment fees were incorrectly
recognized and (ii) stock-based compensation expense related to certain
restricted stock awards granted under the Long-Term Incentive Plan was
understated. The late payment fees and stock-based compensation
adjustments resulted in increases in Other Operation and Maintenance expenses
for the year ended December 31, 2008 of $6 million and $9 million,
respectively.
Depreciation
and Amortization
Depreciation
and Amortization expenses increased by $11 million to $377 million in 2008
from $366 million in 2007. The increase was primarily due
to:
·
An
increase of $21 million due to higher amortization by ACE of stranded
costs as a result of an October 2007 Transition Bond Charge rate increase
(offset in Default Supply Revenue)
·
An
increase of $7 million due to utility plant
additions.
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $15 million due to a change in depreciation rates in
accordance with the 2007 Maryland Rate
Orders.
Deferred
Electric Service Costs
Deferred
Electric Service Costs, which relate only to ACE, decreased by $77 million
to income of $9 million in 2008 from an expense of $68 million in
2007. The decrease was primarily due to:
·
A
decrease of $46 million due to a lower rate of recovery associated with
deferred energy costs.
·
A
decrease of $29 million due to a lower rate of recovery of costs
associated with energy and capacity purchased under the
NUGs.
·
A
decrease of $17 million due to a lower rate of recovery associated with
deferred transmission costs.
62
PEPCO
HOLDINGS
The
aggregate amount of these decreases was partially offset
by:
·
An
increase of $15 million primarily due to a higher rate of recovery
associated with Demand Side Management program
costs.
Deferred
Electric Service Costs are substantially offset in Regulated T&D Electric
Revenue and Other Operation and Maintenance.
Impairment
Losses
During
2008, Pepco Holdings recorded pre-tax impairment losses of $2 million ($1
million after-tax) related to a joint-venture investment owned by Conectiv
Energy. During 2007, Pepco Holdings recorded pre-tax impairment
losses of $2 million ($1 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 in 2007 of $33 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” herein.
Other
Income (Expenses)
Other
Expenses (which are net of Other Income) increased by $16 million to a net
expense of $300 million in 2008 from a net expense of $284 million in 2007 due
to:
·
A
decrease of $15 million in income from equity
investments.
·
A
decrease of $5 million in Contribution in Aid of Construction tax gross-up
income.
The aggregate amount of these decreases in income was partially offset
by:
·
A
net decrease of $10 million in interest
expense.
Income
Tax Expense
PHI’s effective tax rates for the years
ended December 31, 2008 and 2007 were 35.9% and 36.0%, respectively. While the
change in the effective rate between 2008 and 2007 was minimal, the effective
rate in each year was impacted by certain non-recurring items. In
2008, PHI recorded certain tax benefits that reduced its overall effective tax
rate, primarily representing net interest income accrued on effectively settled
and uncertain tax positions (including interest related to the tentative
settlements with the IRS on the mixed service cost and like-kind exchange issues
discussed below and a claim made with the IRS related to ACE’s tax
reporting of fuel over- and under-recoveries), interest income received in 2008
on the Maryland state tax refund referred to below, and deferred tax adjustments
related to additional analysis of its deferred tax balances completed in
2008. These benefits were partially offset by limited federal and
state tax benefits related to the charge taken on the cross-border energy lease
investments in the second
63
PEPCO
HOLDINGS
quarter
of 2008. In 2007, PHI recorded the receipt of Pepco’s Maryland state
tax refund in the third quarter of 2007 as a reduction in income tax
expense.
During
the second quarter 2008, PHI reached a tentative settlement with the IRS
concerning the treatment by Pepco, DPL and ACE of mixed service construction
costs for income tax purposes during the period 2001 to 2004. On the
basis of the tentative settlement, PHI updated its estimated liability related
to mixed service costs and, as a result, recorded a net reduction in its
liability for unrecognized tax benefits of $19 million and recognized after-tax
interest income of $7 million in the second quarter of 2008. See Note
(16), “Commitments and Contingencies—Regulatory and Other Matters — IRS Mixed
Service Cost Issue,” to the consolidated financial statements of PHI set forth
in Item 8 of this Form 10-K.
During
the fourth quarter of 2008, PHI reached a final settlement with the IRS
concerning a transaction between Conectiv and an unaffiliated third party that
was treated by Conectiv as a “like-kind exchange” under Internal Revenue Code
Section 1031. PHI’s reserve for this issue was more conservative than
the actual settlement and resulted in the reversal of a total of $5 million
(after-tax) in excess accrued interest related to this matter in the fourth
quarter of 2008. See Note (16), “Commitments and Contingencies —
Regulatory and Other Matters — IRS Examination of Like-Kind Exchange
Transaction” to the consolidated financial statements of PHI set forth in Item 8
of this Form 10-K.
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
$
5,119
$
125
Conectiv
Energy
2,206
1,964
242
Pepco
Energy Services
2,309
1,669
640
Other
Non-Regulated
76
91
(15)
Corp.
& Other
(469)
(480)
11
Total
Operating Revenue
$
9,366
$
8,363
$
1,003
64
PEPCO
HOLDINGS
Power
Delivery
The following table categorizes Power
Delivery’s operating revenue by type of revenue.
2007
2006
Change
Regulated
T&D Electric Revenue
$
1,592
$
1,496
$
96
Default
Supply Revenue
3,295
3,309
(14)
Other
Electric Revenue
66
58
8
Total
Electric Operating Revenue
4,953
4,863
90
Regulated
Gas Revenue
211
205
6
Other
Gas Revenue
80
51
29
Total
Gas Operating Revenue
291
256
35
Total
Power Delivery Operating Revenue
$
5,244
$
5,119
$
125
Regulated Transmission and Distribution
(T&D) Electric Revenue includes revenue from 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. Regulated T&D Electric Revenue also includes transmission
service revenue that PHI’s utility subsidiaries receive as transmission owners
from PJM.
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 sale of excess system
capacity.
In response to an order issued by the
NJBPU regarding changes to ACE’s retail transmission rates, ACE has established
deferred accounting treatment for the difference between the rates that ACE is
authorized to charge its customers for the transmission of default electricity
supply and the cost that ACE incurs. Under the deferral arrangement,
any over or under recovery is deferred as part of Deferred Electric Service
Costs pending an adjustment of retail rates in a future
proceeding. As a consequence of the order, effective January 1,2008, ACE’s retail transmission revenue is being recorded as Default Supply
Revenue, rather than as Regulated T&D Electric Revenue, thereby conforming
to the practice of PHI’s other utility subsidiaries, which previously
established deferred accounting treatment for any over or under
65
PEPCO
HOLDINGS
recovery
of retail transmission rates relative to the cost incurred. In
addition, ACE’s retail transmission revenue for the period prior to
January 1, 2008 has been reclassified to Default Supply Revenue in order to
conform to the current period presentation.
Electric Operating Revenue
Regulated
T&D Electric Revenue
2007
2006
Change
Residential
$
579
$
550
$
29
Commercial
720
689
31
Industrial
26
27
(1)
Other
267
230
37
Total
Regulated T&D Electric Revenue
$
1,592
$
1,496
$
96
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue, (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) any
necessary Revenue Decoupling Adjustments.
Regulated
T&D Electric Sales (GWh)
2007
2006
Change
Residential
17,946
17,139
807
Commercial
29,137
28,378
759
Industrial
3,974
4,119
(145)
Other
261
260
1
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
197
196
1
Industrial
2
2
-
Other
2
2
-
Total
Regulated T&D Electric Customers
1,823
1,805
18
Regulated T&D Electric Revenue
increased by $96 million primarily due to:
·
An
increase of $43 million in sales due to higher weather-related sales (a
17% increase in Cooling Degree Days and a 12% increase in Heating Degree
Days).
·
An
increase of $29 million in Other Regulated T&D Electric Revenue from
the resale of energy and capacity purchased under the Panda PPA, (offset
in Fuel and Purchased Energy and Other Services Cost of
Sales).
66
PEPCO
HOLDINGS
·
An
increase of $20 million due to a distribution rate change under the 2007
Maryland Rate Orders that became effective in June 2007, including a
positive $5 million Revenue Decoupling
Adjustment.
·
An
increase of $12 million due to higher pass-through revenue primarily
resulting from tax rate increases in the District of Columbia (primarily
offset in Other Taxes).
·
An
increase of $5 million due to customer growth of 1% in
2007.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $10 million due to a change in the Delaware rate structure
effective May 1, 2006, which shifted revenue from Regulated T&D
Electric Revenue to Default Supply
Revenue.
·
`A
decrease of $4 million due to a Delaware base rate reduction effective May1, 2006.
Default Electricity Supply
Default
Supply Revenue
2007
2006
Change
Residential
$
1,843
$
1,508
$
335
Commercial
1,073
1,363
(290)
Industrial
94
110
(16)
Other
285
328
(43)
Total
Default Supply Revenue
$
3,295
$
3,309
$
(14)
Other Default Supply Revenue consists
primarily of revenue from the resale of energy and capacity purchased under 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)
67
PEPCO
HOLDINGS
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 $14 million primarily due to:
·
A
decrease of $346 million primarily due to commercial and industrial
customers electing to purchase electricity from competitive
suppliers.
·
A
decrease of $95 million due to differences in consumption among the
various customer rate classes.
·
A
decrease of $46 million 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.
·
A
decrease of $4 million due to a DPL adjustment to reclassify market-priced
supply revenue from Regulated T&D Electric Revenue in
2006.
The aggregate amount of these decreases
was partially offset by:
·
An
increase of $379 million due to annual increases in market-based Default
Electricity Supply rates.
·
An
increase of $87 million due to higher weather-related sales (a 17%
increase in Cooling Degree Days and a 12% increase in Heating Degree
Days).
·
An
increase of $10 million 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
Other Electric Revenue increased $8
million to $66 million in 2007 from $58 million in 2006 primarily due to
increases in revenue related to pole rentals and late payment fees.
68
PEPCO
HOLDINGS
Gas Operating Revenue
Regulated
Gas Revenue
2007
2006
Change
Residential
$
124
$
116
$
8
Commercial
73
73
-
Industrial
8
10
(2)
Transportation
and Other
6
6
-
Total
Regulated Gas Revenue
$
211
$
205
$
6
Regulated
Gas Sales (billion cubic feet)
2007
2006
Change
Residential
8
7
1
Commercial
5
5
-
Industrial
1
1
-
Transportation
and Other
7
5
2
Total
Regulated Gas Sales
21
18
3
Regulated
Gas Customers (in thousands)
2007
2006
Change
Residential
112
112
-
Commercial
10
9
1
Industrial
-
-
-
Transportation
and Other
-
-
-
Total
Regulated Gas Customers
122
121
1
Regulated Gas Revenue increased by $6
million primarily due to:
·
An
increase of $12 million due to colder weather (a 15% increase in Heating
Degree Days).
·
An
increase of $6 million due to base rate increases effective in November
2006 and April 2007.
·
An
increase of $5 million due to differences in consumption among the various
customer rate classes.
·
An
increase of $3 million due to customer growth of 1% in
2007.
The aggregate amount of these increases
was partially offset by:
69
PEPCO
HOLDINGS
·
A
decrease of $18 million due to Gas Cost Rate 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
Other Gas Revenue increased by $29
million to $80 million in 2007 from $51 million in 2006 primarily due to higher
off-system sales (partially offset in Fuel and Purchased Energy and Other
Services Cost of Sales). The gas sold off-system resulted from
increased demand from unaffiliated third party electric generators during
periods of low customer demand for natural gas.
Conectiv
Energy
Conectiv Energy Gross
Margin
Merchant Generation & Load Service
consists primarily of electric power, capacity and ancillary services sales from
Conectiv Energy’s generating plants; tolling arrangements entered into to sell
energy and other products from Conectiv Energy’s generating plants and to
purchase energy and other products from generating plants of other companies;
hedges of power, capacity, fuel and load; the sale of excess fuel (primarily
natural gas); natural gas transportation and storage; emission allowances;
electric power, capacity, and ancillary services sales pursuant to competitively
bid contracts entered into with affiliated and non-affiliated companies to
fulfill their default electricity supply obligations; and fuel switching
activities made possible by the multi-fuel capabilities of some of Conectiv
Energy’s power plants.
Energy Marketing activities consist
primarily of wholesale natural gas and fuel oil marketing, the activities of the
short-term power desk, which generates margin by capturing price differences
between power pools and locational and timing differences within a power pool,
and power origination activities, which primarily represent the fixed margin
component of structured power transactions such as default supply
service.
Generation Fuel
and Purchased Power Expenses ($ millions) 3:
Generation Fuel Expenses 4,5
Natural Gas6
$
268
$
175
$
93
Coal
62
53
9
Oil
34
27
7
Other7
2
4
(2)
Total
Generation Fuel Expenses
$
366
$
259
$
107
Purchased Power Expenses 5
$
480
$
431
$
49
Statistics:
2007
2006
Change
Generation
Output (MWh):
Base-Load 8
2,232,499
1,814,517
417,982
Mid-Merit (Combined Cycle) 9
3,341,716
2,081,873
1,259,843
Mid-Merit (Other) 10
190,253
115,120
75,133
Peaking
146,486
131,930
14,556
Tolled
Generation
160,755
94,064
66,691
Total
6,071,709
4,237,504
1,834,205
Load Service Volume (MWh) 11
7,075,743
8,514,719
(1,438,976)
Average
Power Sales Price
12($/MWh):
Generation Sales 4
$
82.19
$
77.69
$
4.50
Non-Generation Sales 13
$
70.43
$
58.49
$
11.94
Total
$
74.34
$
62.54
$
11.80
Average on-peak spot power price at PJM East Hub
($/MWh) 14
$
77.85
$
65.29
$
12.56
Average around-the-clock spot power price at PJM
East Hub ($/MWh) 14
$
63.92
$
53.07
$
10.85
Average spot natural gas price at market area M3
($/MMBtu)15
$
7.76
$
7.31
$
0.45
Weather (degree days at Philadelphia Airport):
16
Heating
degree days
4,560
4,205
355
Cooling
degree days
1,513
1,136
377
1
Includes
$442 million and $471 million of affiliate transactions for 2007 and 2006,
respectively. The 2006 amount has been reclassified to exclude
$193 million of intra-affiliate transactions that were reported gross in
2006 at the segment
level.
2
Includes
$7 million and $5 million of affiliate transactions for 2007 and 2006,
respectively. The 2006 amount has been reclassified to exclude
$193 million of intra-affiliate transactions that were reported gross in
2006 at the segment level. Also, excludes depreciation and
amortization expense of $38 million and $36 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.
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.
71
PEPCO
HOLDINGS
Merchant Generation & Load Service
gross margin increased $69 million primarily due to:
·
An
increase of approximately $77 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 $26 million due to higher capacity prices due to
the implementation of the PJM Reliability Pricing
Model.
·
A
decrease of $33 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 million primarily due to:
·
A
decrease of $5 million due to lower margins in oil
marketing.
·
A
decrease of $4 million due to lower margins in natural gas
marketing.
·
An
increase of $3 million for adjustments related to an unaffiliated
generation operating services agreement that expired in
2006.
Pepco Energy
Services
Pepco Energy Services’ operating
revenue increased $640 million to $2,309 million in 2007 from $1,669 million in
2006 primarily due to:
·
An
increase of $646 million due to higher volumes of retail electric load
served at higher prices in 2007 driven by customer
acquisitions.
·
An
increase of $27 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.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $32 million due primarily to lower construction activity in
2007 and to the sale of five construction businesses in
2006.
Other
Non-Regulated
Other Non-Regulated operating revenue
decreased $15 million to $76 million in 2007 from $91 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:
72
PEPCO
HOLDINGS
·
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
$
3,360
$
3,304
$
56
Conectiv
Energy
1,887
1,709
178
Pepco
Energy Services
2,161
1,531
630
Corp.
& Other
(465)
(478)
13
Total
$
6,943
$
6,066
$
877
Power
Delivery
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 million primarily due
to:
·
An
increase of $445 million in average energy costs, the result of new
Default Electricity Supply
contracts.
·
An
increase of $93 million due to higher weather-related
sales.
·
An
increase of $29 million for energy and capacity purchased under the Panda
PPA.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $472 million primarily due to commercial and industrial
customers electing to purchase an increased amount of electricity from
competitive suppliers.
·
A
decrease of $36 million in the Default Electricity Supply deferral
balance.
·
Fuel
and Purchased Energy expense is primarily offset in Regulated T&D
Electric Revenue, Default Supply Revenue, Regulated Gas Revenue or Other
Gas Revenue.
73
PEPCO
HOLDINGS
Conectiv
Energy
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
Pepco Energy Services’ Fuel and
Purchased Energy and Other Services Cost of Sales increased $630 million
primarily due to:
·
An
increase of $636 million due to higher volumes of purchased electricity at
higher prices in 2007 to serve increased retail customer
load.
·
An
increase of $40 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.
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $45 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
$
640
$
27
Conectiv
Energy
127
116
11
Pepco
Energy Services
74
68
6
Other
Non-Regulated
3
4
(1)
Corp.
& Other
(13)
(20)
7
Total
$
858
$
808
$
50
Other
Operation and Maintenance expense of the Power Delivery segment increased by $27
million; however, excluding the favorable variance of $34 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
million. The $61 million increase was primarily due to:
·
An
increase of $16 million in employee-related
costs.
·
An
increase of $11 million in preventative maintenance and system operation
costs.
·
An
increase of $7 million in customer service operation
expenses.
74
PEPCO
HOLDINGS
·
An
increase of $4 million in costs associated with Default Electricity Supply
(primarily deferred and
recoverable).
·
An
increase of $4 million in regulatory
expenses.
·
An
increase of $4 million in accounting service
expenses.
·
An
increase of $3 million due to various construction project write-offs
related to customer requested work.
·
An
increase of $3 million in Demand Side Management program costs (offset in
Deferred Electric Service Costs).
·
An
increase of $3 million due to higher bad debt
expenses.
Other Operation and Maintenance expense
for Conectiv Energy increased by $11 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 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 $7 million due to:
·
An
increase in employee-related costs.
Depreciation and
Amortization
Depreciation and Amortization
expenses decreased by $47 million to $366 million in 2007 from $413 million
in 2006. The decrease is primarily due to:
·
A
decrease of $31 million in ACE’s regulatory asset amortization resulting
primarily from the 2006 sale of ACE’s interests in Keystone and
Conemaugh.
·
A
decrease of $19 million in depreciation due to a change in depreciation
rates in accordance with the 2007 Maryland Rate
Order.
Other Taxes
Other Taxes increased by $14 million to
$357 million in 2007 from $343 million in 2006. The increase was
primarily due to:
75
PEPCO
HOLDINGS
·
An
increase in 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 million to $68 million in 2007 from $22
million in 2006. The increase is primarily due to:
·
An
increase of $38 million due to a higher rate of recovery associated with
energy and capacity purchased under the
NUGs.
·
An
increase of $12 million due to a higher rate of recovery associated with
deferred energy costs.
The aggregate amount of these increases
was partially offset by:
·
A
decrease of $3 million due to a lower rate of recovery associated with
Demand Side Management program
costs.
Deferred
Electric Service Costs are substantially offset in Regulated T&D Electric
Revenue and Other Operation and Maintenance.
Impairment
Losses
During 2007, Pepco Holdings recorded
pre-tax impairment losses of $2 million ($1 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 $19 million ($14 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 in 2007 of $33 million in operating
expenses and certain other costs as damages in the Mirant bankruptcy
settlement. See “Capital Resources and Liquidity — Proceeds from
Settlement of Mirant Bankruptcy Claims” herein.
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
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 approximately $20 million, with a
corresponding decrease to the effective tax rate of 3.7%.
CAPITAL
RESOURCES AND LIQUIDITY
This section discusses Pepco Holdings’
working capital, cash flow activity, capital requirements and other uses and
sources of capital.
76
PEPCO
HOLDINGS
Working
Capital
At December 31, 2008, Pepco Holdings’
current assets on a consolidated basis totaled $2.6 billion and its current
liabilities totaled $2 billion. At December 31, 2007, Pepco Holdings’
current assets on a consolidated basis totaled $2 billion and its current
liabilities totaled $2 billion. The increase in working capital from December31, 2007 to December 31, 2008 is primarily due to an increase in cash as a
result of the issuance of long-term debt during the fourth quarter of
2008.
At December 31, 2008, Pepco Holdings’
cash and current cash equivalents totaled $384 million, of which $343 million
was invested in money market funds that invest in U.S. Treasury obligations, and
the balance was held as cash and uncollected funds. Current restricted cash
(cash that is available to be used only for designated purposes) totaled $10
million. At December 31, 2007, Pepco Holdings’ cash and current
cash equivalents totaled $55 million and its current restricted cash totaled $15
million. See “Capital Requirements — Contractual Arrangements with Credit Rating
Triggers or Margining Rights” herein 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.
PHI,
Pepco, DPL and ACE maintain a credit facility to provide for their respective
short-term liquidity needs. The aggregate borrowing limit under this
primary credit facility is $1.5 billion, all or any portion of which may be used
to obtain loans or to issue letters of credit. PHI’s credit limit
under the facility is $875 million. The credit limit of each of
Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt
the company is permitted to have outstanding by its regulatory authorities,
except that the aggregate amount of credit used by Pepco, DPL and ACE at any
given time collectively may not exceed $625 million. The interest
rate payable by each company on utilized funds is, at the borrowing company’s
election, (i) the greater of the prevailing prime rate and the federal funds
effective rate plus 0.5% or (ii) the prevailing Eurodollar rate, plus a margin
that varies according to the credit rating of the borrower. The
facility also includes a “swingline loan sub-facility” pursuant to which each
company may make same day borrowings in an aggregate amount not to exceed $150
million. Any swingline loan must be repaid by the borrower within
seven days of receipt thereof. All indebtedness incurred under the
facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of
the principal balance of the loans outstanding on the expiration date continued
as non-revolving term loans for a period of one year from such expiration
date.
The
facility is intended to serve primarily as a source of liquidity to support the
commercial paper programs of the respective companies. The companies also are
permitted to use the facility to borrow funds for general corporate purposes and
issue letters of credit. In order for a borrower to use the facility, certain
representations and warranties must be true and correct, and the borrower must
be in compliance with specified covenants, including (i) the requirement that
each borrowing company maintain a ratio of total indebtedness to total
capitalization of 65% or less, computed in accordance with the terms of the
credit agreement, which calculation excludes from the definition of total
indebtedness certain trust preferred securities and deferrable interest
subordinated debt (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than certain sales
and dispositions, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other than permitted
liens. The absence of a material adverse change in the borrower’s
business, property, and results of operations or financial condition is not a
condition to the availability of credit under the facility. The facility does
not include any rating triggers.
In
November 2008, PHI entered into a second credit facility in the amount of $400
million with a syndicate of nine lenders. Under the facility, PHI may
obtain revolving loans and swingline loans over the term of the facility, which
expires on November 6, 2009. The facility does not provide for the issuance of
letters of credit. All indebtedness incurred under the facility is
unsecured. The interest rate payable on funds borrowed under the facility is, at
PHI’s election, based on either (a) the prevailing Eurodollar rate or (b) the
highest of (i) the prevailing prime rate, (ii) the federal funds effective rate
plus 0.5% or (iii) the one-month Eurodollar rate plus 1.0%, plus a margin that
varies according to the credit rating of PHI. Under the swingline loan
sub-facility, PHI may obtain loans for up to seven days in an aggregate
principal amount which does not exceed 10% of the aggregate borrowing limit
under the facility. In order to obtain loans under the facility, PHI must be in
compliance with the same covenants and conditions that it is required to satisfy
for utilization of the primary credit facility. The absence of a material
adverse
78
PEPCO
HOLDINGS
change in
PHI’s business, property, and results of operations or financial condition is
not a condition to the availability of credit under the facility. The facility
does not include any ratings triggers.
Typically,
PHI and its utility subsidiaries issue commercial paper if required to meet
their short-term working capital requirements. Given the recent lack
of liquidity in the commercial paper markets, however, the companies have
borrowed under the primary credit facility to maintain sufficient cash on hand
to meet daily short-term operating needs. As of December 31,2008, PHI had an outstanding loan of $50 million and Pepco had an outstanding
loan of $100 million under the facility. In January 2009, PHI borrowed an
additional $150 million under the facility.
Cash
and cash equivalents reported on the Balance Sheet total $384 million,
which includes the $343 million invested in money market funds and $41
million held in cash and uncollected
funds.
During
the months of January and February 2009, the total cash and credit facilities
available to PHI on a consolidated basis ranged from a low of $1.1 billion to a
high of $1.7 billion, and averaged $1.4 billion. The total cash and
credit facilities available to the utility subsidiaries collectively ranged from
a low of $673 million to a high of $1 billion, and averaged $831
million.
Cash
Flow Activity
PHI’s cash flows for 2008, 2007, and
2006 are summarized below.
Cash
Source (Use)
2008
2007
2006
(Millions
of dollars)
Operating
Activities
$
413
$
795
$
203
Investing
Activities
(714)
(582)
(230)
Financing
Activities
630
(207)
(46)
Net
increase (decrease) in cash and cash equivalents
$
329
$
6
$
(73)
79
PEPCO
HOLDINGS
Operating Activities
Cash flows from operating activities
are summarized below for 2008, 2007, and 2006.
Cash
Source (Use)
2008
2007
2006
(Millions
of dollars)
Net
Income
$
300
$
334
$
248
Non-cash
adjustments to net income
1,073
382
613
Changes
in working capital
(960)
79
(658)
Net
cash from operating activities
$
413
$
795
$
203
Net cash from operating activities was
$382 million lower for the year ended December 31, 2008 compared to the
year ended December 31, 2007. In addition to a $34 million decrease
in net income, the primary contributor was a $336 million increase in cash
collateral requirements associated with Competitive Energy
activities. The cash collateral requirements of the Competitive
Energy businesses fluctuate significantly based on changes in energy market
prices.
As of December 31, 2008 and 2007,
the combined net cash collateral positions of the Pepco Energy Services and
Conectiv Energy businesses were net cash posted of $331 million and $90 million,
respectively. As energy prices have declined in the second half of
2008, the collateral that the Competitive Energy businesses have been required
to post has increased substantially.
In addition, the transfer by Pepco of
the Panda PPA to Sempra Energy Trading LLC had an impact on 2008 cash flows from
operating activities. Non-cash adjustments to net income reflect the
change in restricted cash equivalents used to make the payment and changes in
working capital include the reduction in the regulatory liability established to
help offset future above-market capacity and energy purchase costs.
Net cash from operating activities in
2007 was $592 million higher than in 2006. In addition to an increase
in net income, the factors that primarily contributed to the increase
were: (i) a decrease of $203 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 Note (16), “Commitments and
Contingencies ¾
Regulatory and Other Matters — IRS Mixed Service Cost Issue” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K), (ii) a
decrease in cash collateral requirements associated with Competitive Energy
activities, and (iii) the receipt of the proceeds of the Mirant bankruptcy
settlement, of which $399 million was designated as operating cash flows and $15
million was designated as investing cash flows.
80
PEPCO
HOLDINGS
Investing Activities
Cash flows used by investing activities
during 2008, 2007, and 2006 are summarized below.
Cash
(Use) Source
2008
2007
2006
(Millions
of dollars)
Construction
expenditures
$
(781)
$
(623)
$
(475)
Cash
proceeds from sale of other assets
56
11
182
All
other investing cash flows, net
11
30
63
Net
cash used by investing activities
$
(714)
$
(582)
$
(230)
Net cash used by investing activities
increased $132 million for the year ended December 31, 2008 compared to the
year ended December 31, 2007. The increase was due primarily to (i)
$158 million increase in capital expenditures, of which $96 million was
attributable to Conectiv Energy and $33 million was attributable to Power
Delivery, and (ii) the receipt by Pepco in 2007 of the proceeds of the Mirant
bankruptcy settlement of which $15 million was designated as a reimbursement of
certain investments in property, plant and equipment, offset by (iii) an
increase of $45 million in cash proceeds from the sale of assets. The
increase in Conectiv Energy capital expenditures was primarily due to the
construction of new generation plants. The increase in Power Delivery capital
expenditures was primarily attributable to capital costs associated with new
customer services, distribution reliability, and transmission. The proceeds from
the sale of assets in 2008 consisted primarily of $54 million received from
DPL’s sale of its Virginia retail electric distribution assets and wholesale
electric transmission assets. Proceeds from the sale of assets in
2007 consisted primarily of $9 million received from the sale by ACE of the B.L.
England generating facility.
Net cash used by investing activities
in 2007 was $352 million higher than in 2006 primarily due to: (i) a
$148 million increase in capital expenditures, $107 million of which relates to
Power Delivery, and (ii) a decrease of $171 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 other assets in 2006 consisted
primarily of $175 million from the sale of ACE’s interest in the Keystone and
Conemaugh generating facilities. Proceeds from the sale of other
assets in 2007 consisted primarily of $9 million received from the sale of the
B.L. England generating facility. Cash flows from investing
activities in 2007 also include $15 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.
81
PEPCO
HOLDINGS
Financing Activities
Cash flows used by financing activities
during 2008, 2007 and 2006 are summarized below.
Cash
(Use) Source
2008
2007
2006
(Millions
of dollars)
Dividends
paid on common and preferred stock
$
(222)
$
(203)
$
(199)
Common
stock issued through the Dividend
Reinvestment
Plan (DRP)
29
28
30
Issuance
of common stock
287
200
17
Redemption
of preferred stock of subsidiaries
-
(18)
(22)
Issuances
of long-term debt
1,150
704
515
Reacquisition
of long-term debt
(590)
(855)
(578)
Issuances
(repayments) of short-term debt, net
26
(61)
193
Cost
of issuances
(30)
(7)
(6)
All
other financing cash flows, net
(20)
5
4
Net
cash provided by (used by) financing activities
$
630
$
(207)
$
(46)
Net cash provided by financing
activities in 2008 was $837 million higher than in 2007. Net cash
used by financing activities in 2007 was $161 million higher than in
2006.
Common
Stock Dividends
Common stock dividend payments were
$222 million in 2008, $203 million in 2007, and $198 million in
2006. The increase in common dividends paid in 2008 was the result of
additional shares outstanding (primarily from PHI’s sale of 6.5 million shares
of common stock in November 2007) and a quarterly dividend increase from 26
cents per share to 27 cents per share beginning in the first quarter of 2008.
The increase in common dividends paid in 2007 was due to the issuance of the
additional shares under the DRP.
Changes
in Outstanding Common Stock
In
November 2008, PHI sold 16.1 million shares of common stock in a registered
offering at a price per share of $16.50, resulting in gross proceeds of $265
million. 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 $176 million.
Under the
DRP, PHI issued approximately 1.3 million shares of common stock in 2008,
approximately 1 million shares of common stock in 2007 and approximately 1.2
million shares of common stock in 2006.
Changes in Outstanding Preferred
Stock
Cash flows from the redemption of
preferred stock in 2008, 2007 and 2006 are summarized in the chart
below.
82
PEPCO
HOLDINGS
Preferred
Stock Redemptions
Redemption
Price
Shares
Redeemed
Aggregate
Redemption Costs for years ended December 31,
Cash flows from the issuance and
redemption of long-term debt in 2008, 2007 and 2006 are summarized in the charts
below.
2008
2007
2006
Issuances
(Millions
of dollars)
PHI
6.0%
unsecured notes due 2019
$
-
$
200
$
-
6.125%
unsecured notes due 2017
-
250
-
5.9%
unsecured notes due 2016
-
-
200
-
450
200
Pepco
6.5%
senior notes due 2037 (a)
250
-
-
Auction
rate tax-exempt bonds due 2022 (a)
-
-
110
6.5%
senior notes due 2037 (a)
-
250
-
7.9%
first mortgage bonds due 2038
250
-
-
500
250
110
DPL
6.4%
first mortgage bonds due 2013
250
-
-
5.22%
unsecured notes due 2016
-
-
100
250
(b)
-
100
ACE
5.8%
senior notes due 2036 (a)
-
-
105
7.75%
first mortgage bonds due 2018
250
-
-
250
-
105
Pepco
Energy Services
-
4
-
$
1,000
(b)
$
704
$
515
(a)
Secured by an outstanding series of First Mortgage Bonds. See
Note (11), “Debt,” to the consolidated financial statements of PHI in Item
8 of this Form 10-K.
(b)
Excludes DPL $150 million 2-year bank loan that was converted to a 364-day
bank loan.
83
PEPCO
HOLDINGS
2008
2007
2006
Redemptions
(Millions
of dollars)
PHI
3.75%
unsecured notes due 2006
$
-
$
-
$
300
5.5%
unsecured notes due 2007
-
500
-
-
500
300
Pepco
7.64%
medium term notes due 2007
-
35
-
6.25%
first mortgage bonds due 2007
-
175
-
6.5%
first mortgage bonds due 2008
78
-
-
Auction rate, tax-exempt bonds
due 2022 (a)
110
-
-
Auction
rate, tax-exempt bonds due 2022-2024
-
-
110
5.875%
first mortgage bonds due 2008
50
-
-
Variable
rate notes due 2006
-
-
50
238
210
160
DPL
7.08%
medium term notes due 2007
-
12
-
Auction
rate, tax-exempt bonds due 2030-2038 (a)
58
-
-
Auction
rate, tax-exempt bonds due 2030-2031 (a)
36
-
-
8.125%
medium term notes due 2007
-
50
-
6.95%
first mortgage bonds due 2008
-
3
3
6.95%
first mortgage bonds due 2008
4
-
-
Auction
rate, tax-exempt bonds due 2023 (a)
18
-
-
6.75%
medium term notes due 2006
-
-
20
116
65
23
ACE
6.18%-6.19%
medium term notes
-
-
65
6.79%
medium term notes due 2008
15
-
-
Auction
rate, tax-exempt bonds due 2029 (a)
25
-
-
Auction
rate, tax-exempt bonds due 2029 (a)
30
-
-
6.77%
medium term notes due 2008
1
-
-
7.52%
medium term notes due 2007
-
15
-
6.73%-6.75%
medium term notes due 2008
25
-
-
7.15%
medium term notes due 2007
-
1
-
6.71%-6.73%
medium term notes due 2008
9
-
-
Securitization
bonds due 2006-2008
31
30
29
136
46
94
PCI
7.62%
medium term notes due 2007
-
34
-
8.24%
medium term note due 2008
92
-
-
92
34
-
Pepco
Energy Services
8
-
1
$
590
$
855
$
578
(a)
Held by the indicated company pending resale to the public. See
“Purchase of Tax-Exempt Auction Rate Bonds” below.
Purchase of Tax-Exempt Auction Rate
Bonds
The redemptions in 2008 shown below
include the purchase at par by PHI subsidiaries of $276 million in aggregate
principal amount of insured tax-exempt auction rate bonds issued by municipal
authorities for the benefit of the respective PHI subsidiaries. These
purchases were made in response to disruption in the market for municipal
auction rate securities that made it
84
PEPCO
HOLDINGS
difficult
for the remarketing agent to successfully remarket the bonds. These
bond purchases consisted of the following:
·
The
purchase by Pepco of Pollution Control Revenue Refunding Bonds issued by
the Maryland Economic Development Corporation of an aggregate principal
amount of $110 million.
·
The
purchase by DPL of Exempt Facilities Refunding Revenue Bonds issued by The
Delaware Economic Development Authority in the aggregate principal amount
of $112 million.
·
The
purchase by ACE of (i) Pollution Control Revenue Refunding Bonds issued by
Cape May County in the aggregate principal amount of $32 million and (ii)
Pollution Control Revenue Refunding Bonds issued by Salem County in the
aggregate principal amount of $23
million.
The obligations of the PHI subsidiaries
with respect to these tax-exempt bonds are considered to be extinguished for
accounting purposes; however, each of the companies continues to hold the bonds,
while monitoring the market and evaluating the options for reselling the bonds
to the public at some time in the future.
Changes
in Short-Term Debt
Due to
the recent capital and credit market disruptions, the market for commercial
paper in 2008 has been severely restricted for most companies. As a result, PHI
and its subsidiaries have not been able to issue commercial paper on a
day-to-day basis either in amounts or with maturities that they have typically
required for cash management purposes. Given their restricted access to the
commercial paper market and the general uncertainty in the credit markets, PHI
and each of its utility subsidiaries borrowed under the primary credit facility
to create a cash reserve for future short-term operating needs. As of
December 31, 2008, PHI had a loan of $50 million outstanding and Pepco had a
loan of $100 million outstanding under this facility. In January
2009, PHI borrowed an additional $150 million under this facility.
In March
2008, DPL obtained a $150 million unsecured bank loan that matures in July
2009. Interest on the loan is calculated at a variable
rate. In May 2008, Pepco obtained a $25 million bank loan that
matures on April 30, 2009. Interest on the loan is calculated at a
variable rate.
The following insured Variable Rate
Demand Bonds (VRDBs) repurchased in 2008 by The Bank of New York Mellon, as bond
trustee, were tendered to the trustee by the holders in accordance with the
terms of the VRDBs for purchase at par:
·
$17
million of Pollution Control Revenue Refunding Bonds 1997 Series A issued
by Salem County for the benefit of ACE,
and
·
$5
million of Pollution Control Revenue Refunding Bonds 1997 Series B issued
by Salem County for the benefit of
ACE.
85
PEPCO
HOLDINGS
The purchase of these VRDBs was
financed by The Bank of New York Mellon under Standby
Bond Purchase Agreements for the respective series. If these VRDBs
cannot be remarketed by the remarketing agent prior to the first anniversary of
the purchase of the VRDBs by the bond trustee, ACE will be obligated
to redeem 1/10th of the principal amount of each series of VRDBs held by
the bond trustee every six months thereafter. While the VRDBs are
held by the bond trustee, ACE is obligated to pay interest on such bonds at a
rate equal to the prime rate or LIBOR plus 50 basis points.
In
November 2008, DPL repurchased $9 million of Variable Rate Demand Bonds due
2024.
In 2007,
PHI redeemed a total of $36 million in short-term debt with cash from
operations.
In 2006, Pepco and DPL issued
short-term debt of $67 million and $91 million, respectively, in order to cover
capital expenditures and tax obligations throughout the year.
Sale
of Virginia Retail Electric Distribution and Wholesale Transmission
Assets
In
January 2008, DPL completed (i) the sale of its retail electric
distribution assets on the Eastern Shore of Virginia to A&N Electric
Cooperative for a purchase price of approximately $49 million, after closing
adjustments, and (ii) the sale of its wholesale electric transmission assets
located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative
for a purchase price of approximately $5 million, after closing
adjustments.
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 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 million and in February 2008, ACE received an additional $4
million in an arbitration settlement relating to the sale. For a
discussion of the accounting treatment of the gains from these sales, see Note
(7), “Regulatory Assets and Regulatory Liabilities,” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K.
Sale
of Interest in Cogeneration Joint Venture
During the first quarter of 2006,
Conectiv Energy recognized a $12 million pre-tax gain ($8 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
On September 5, 2008, Pepco
transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a
payment to Sempra, terminating all further rights, obligations and liabilities
of Pepco under the Panda PPA. The use of the damages received from
Mirant to offset above-market costs of energy and capacity under the Panda PPA
and to make the payment to Sempra reduced the balance of proceeds from the
Mirant settlement to approximately $102 million as of December 31,2008.
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In November 2008, Pepco filed with the
District of Columbia Public Service Commission (DCPSC) and the MPSC proposals to
share with customers the remaining balance of proceeds from the Mirant
settlement in accordance with divestiture sharing formulas previously approved
by the respective commissions. Under Pepco’s proposals, District of
Columbia and Maryland customers would receive a total of approximately
$25 million and $29 million, respectively. On
December 12, 2008, the DCPSC issued a Notice of Proposed Rulemaking
concerning the sharing of the Mirant divestiture proceeds, including the
bankruptcy settlement proceeds. The public comment period for the
proposed rules has expired without any comments being submitted. This
matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the
Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed
a settlement agreement with the MPSC. The settlement, among other
things, provides that of the remaining balance of the Mirant settlement, Pepco
shall distribute $39 million to its Maryland customers through a one-time
billing credit. If the settlement is approved by the MPSC, Pepco
currently estimates that it will result in a pre-tax gain in the range of $15
million to $20 million, which will be recorded when the MPSC issues its final
order approving the settlement.
Pending the final disposition of these
funds, the remaining $102 million in proceeds from the Mirant settlement is
being accounted for as restricted cash and as a regulatory
liability.
Capital
Requirements
Capital Expenditures
Pepco Holdings’ total capital
expenditures for the year ended December 31, 2008 totaled $781 million of which
$587 million was incurred by Power Delivery, $138 million was incurred by
Conectiv Energy, $31 million was incurred by Pepco Energy Services and $25
million was incurred by Corporate and Other. 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 Power Delivery, Conectiv Energy, Pepco Energy Services
and Corporate and Other for the five-year period 2009 through 2013.
For
the Year
2009
2010
2011
2012
2013
Total
(Millions
of Dollars)
Power
Delivery
Distribution
$
407
$
401
$
433
$
496
$
532
$
2,269
Distribution
- Blueprint for the Future
47
71
5
112
87
322
Transmission
143
183
249
200
204
979
Transmission
- MAPP
56
193
363
474
300
1,386
Gas
Delivery
20
21
20
21
19
101
Other
41
52
61
57
38
249
Total
for Power Delivery Business
714
921
1,131
1,360
1,180
5,306
Conectiv
Energy
281
118
39
12
13
463
Pepco
Energy Services
11
12
14
15
15
67
Corporate
and Other
5
4
4
4
3
20
Total
PHI
$
1,011
$
1,055
$
1,188
$
1,391
$
1,211
$
5,856
87
PEPCO
HOLDINGS
Pepco Holdings expects to fund these
expenditures through internally generated cash and external
financing.
Distribution,
Transmission and Gas Delivery
The projected capital expenditures
listed in the table for distribution (other than Blueprint for the Future),
transmission (other than the Mid-Atlantic Power Pathway (MAPP)) and gas delivery
are primarily for facility replacements and upgrades to accommodate customer
growth and reliability.
Blueprint
for the Future
During 2007, Pepco, DPL and ACE each
announced an initiative that is referred 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 (DSM) 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, plans include the installation of “smart
meters” for all customers in the District of Columbia, Maryland, Delaware and
New Jersey, 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. Delaware has approved a recovery
mechanism associated with these plans, and work has proceeded to prepare for the
installation of an Advanced Metering Infrastructure (AMI) by the last quarter of
2009.
On December 18, 2008, the DCPSC
conditionally approved five DSM programs. The cost of these programs will be
recovered through a rate surcharge. On December 31, 2008 the
MPSC conditionally approved for both Pepco and DPL, four residential and four
non-residential DSM/energy efficiency programs. The MPSC will
consider an AMI program in a separate proceeding. PHI anticipates
that the costs of these programs will be recovered through a previously approved
surcharge mechanism.
MAPP
Project
In October 2007, the PJM Board of
Managers approved PHI’s proposed MAPP transmission project for construction of a
new 230-mile, 500-kilovolt interstate transmission project at a then-estimated
cost of $1 billion. This MAPP project will originate at Possum Point
substation in northern Virginia, connect into three substations across southern
Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva
Peninsula and terminate at Salem substation in southern New Jersey. This MAPP
project is part of PJM’s Regional Transmission Expansion Plan required to
address the reliability objectives of the PJM RTO system. On December 4, 2008,
the PJM Board approved a direct-current technology for segments of the project
including the Chesapeake Bay Crossing. With this modification, the cost of the
MAPP project currently is estimated at $1.4 billion. PJM has
determined that the line
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PEPCO
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segment
from Possum Point substation to the second substation on the Delmarva Peninsula
(Indian River substation) is required to be operational by June 1,2013. PJM is continuing to evaluate the in-service date for the
remaining 80-miles of line segment to connect the Indian River substation to the
Salem substation. Construction is expected to occur in sections over the
next five year period.
Delta Project
In December 2007, Conectiv Energy
announced a decision to construct a 545 megawatt 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, of which $62
million was expended in 2008 and $63 million in 2007 for three combustion
turbines. Projected expenditures of $230 million in 2009, $95 million
in 2010, and $20 million in 2011 are included in Conectiv Energy’s projected
capital expenditures shown in the table above. The plant is expected
to become operational during the second quarter of 2011.
Cumberland
Project
In 2007, Conectiv Energy began
construction of a new 100 megawatt combustion turbine power plant in Millville,
New Jersey. The total construction expenditures for this project are
expected to be $75 million (of which $41 million and $23 million, respectively,
were incurred in 2008 and 2007), with projected expenditures of $10 million in
2009. These future expenditures are included in Conectiv Energy’s
projected capital expenditures shown in the table above. The plant is expected
to become operational during the second quarter of 2009.
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 $81 million (of which $47 million was expended through December
2008) with projected expenditures of $18 million in 2009.
Dividends
Pepco Holdings’ annual dividend rate on
its common stock is determined by the Board of Directors on a quarterly basis
and takes into consideration, among other factors, current and possible future
developments that may affect PHI’s income and cash flows. In 2008,
PHI’s Board of Directors declared quarterly dividends of 27 cents per share of
common stock payable on March 31, 2008, June 30, 2008, September 30, 2008
and December 31, 2008.
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.
Pension Funding
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
2008 valuation, the PHI Retirement Plan satisfied the minimum funding
requirements of the Employee 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) and that is at least equal to
the funding target as defined under the Pension Protection Act of
2006. The funding target under the Pension Protection Act is 100% of
accrued liabilities phased in over time. The funding target was 92%
for 2008 and is 94% of the accrued liability for 2009. In 2008 and
2007, no contributions were made to the PHI Retirement Plan.
In 2008, the ABO for the PHI Retirement
Plan decreased to $1.57 billion from $1.59 billion in 2007, due to an increase
in the discount rate from 6.25% to 6.50%. The PHI Retirement Plan
assets experienced a negative return of 24% in 2008, below the 8.25% level
assumed in the valuation. As a result of the combination of these
factors, the funding level at year-end 2008 was below both 100% of the ABO and
the funding target for January 1, 2009. Although PHI projects
there will be no minimum funding requirement for 2009 under the Pension
Protection Act, PHI expects to make a discretionary tax-deductible contribution
of approximately $300 million to bring its plan assets to at least the funding
target level for 2009 under the Pension Protection Act. For
additional discussion of PHI’s Pension and Other Postretirement Benefits, see
Note (10), “Pension and Other Postretirement Benefits,” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K.
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PEPCO
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Contractual Obligations and Commercial
Commitments
Summary information about Pepco
Holdings’ consolidated contractual obligations and commercial commitments at
December 31, 2008, is as follows:
Contractual
Maturity
Obligation
Total
Less
than 1 Year
1-3
Years
3-5
Years
After
5 Years
(Millions
of dollars)
Variable
rate demand bonds
$
118
$
118
$
-
$
-
$
-
Stand-by
bond purchase agreement
22
22
-
-
-
Bank
loans and credit facility loans
325
325
-
-
-
Commercial
paper
-
-
-
-
-
Long-term
debt (a)
5,357
82
602
1,345
3,328
Long-term
project funding
21
2
4
4
11
Interest
payments on debt
4,049
320
609
523
2,597
Capital
leases
167
15
30
30
92
Liabilities
and accrued interest
related
to effectively settled
and
uncertain tax positions
165
37
-
7
121
Operating
leases
591
56
119
47
369
Pension
and OPEB plan
contributions
339
339
-
-
-
Non-derivative
fuel and
purchase
power contracts
9,067
3,211
2,902
729
2,225
Total
$
20,221
$
4,527
$
4,266
$
2,685
$
8,743
(a) Includes
transition bonds issued by ACE Funding.
Third Party Guarantees,
Indemnifications and Off-Balance Sheet Arrangements
For a discussion of PHI’s third party
guarantees, indemnifications, obligations and off-balance sheet arrangements,
see Note (16), “Commitments and Contingencies,” to the consolidated financial
statements of PHI set forth in Item 8 of this Form 10-K.
91
PEPCO
HOLDINGS
Energy Contract Net Asset/Liability
Activity
The following table provides detail on
changes in the net asset or liability position of the Competitive Energy
businesses (consisting of the activities of the Conectiv Energy and Pepco Energy
Services segments) with respect to energy commodity contracts from one period to
the next:
Roll-forward
of Fair Value Energy Contract Net Assets (Liabilities)
Less: Reclassification
to realized at settlement of contracts
(97)
Effective
portion of changes in fair value - recorded in Other Comprehensive
Income
(315)
Cash
flow hedge ineffectiveness - recorded in earnings
(3)
Total
Fair Value Energy Contract Net Liabilities at December 31,2008
$
(314)
Detail
of Fair Value Energy Contract Net Liabilities at December 31, 2008 (see
above)
Total
Current
Assets (unrealized gains — derivative contracts)
$
126
Noncurrent
Assets (other assets)
13
Total
Fair Value Energy Contract Assets
139
Current
Liabilities (other current liabilities)
(367)
Noncurrent
Liabilities (other liabilities)
(86)
Total Fair Value Energy Contract Liabilities
(453)
Total
Fair Value Energy Contract Net Liabilities
$
(314)
(a)
Includes
all SFAS No. 133 hedge activity and trading activities recorded at fair
value through Accumulated Other Comprehensive Income (AOCI) or on the
Statements of Earnings, as
required.
The $314 million net liability on
energy contracts at December 31, 2008 was primarily attributable to losses on
power swaps and natural gas futures and swaps designated as hedges of future
energy purchases or production under Statement of Financial Accounting Standards
(SFAS) No. 133. Prices of electricity and natural gas declined during
the second half of 2008, which resulted in unrealized losses on the energy
contracts of the Competitive Energy businesses. These businesses
recorded unrealized losses of $315 million on energy contracts in Other
Comprehensive Income as these energy contracts were effective hedges under SFAS
No. 133. When these energy contracts settle, the related realized
gains or losses are expected to be largely offset by the realized loss or gain
on future energy purchases or production that will be used to settle the sales
obligations of the Competitive Energy businesses to their
customers.
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PEPCO
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PHI uses its best estimates to
determine the fair value of the commodity and derivative contracts that its
Competitive Energy businesses hold and sell. The fair values in each
category presented below reflect forward prices and volatility factors as of
December 31, 2008 and are subject to change as a result of changes in these
factors:
Maturity
and Source of Fair Value of Energy Contract Net Assets
(Liabilities)
Includes
all SFAS No. 133 hedge activity and trading activities recorded at fair
value through AOCI or on the Statements of Earnings, as
required.
(b)
Prices
provided by other external sources reflect information obtained from
over-the-counter brokers, industry services, or multiple-party on-line
platforms that is readily observable in the
market.
(c)
Modeled
values include significant inputs, usually representing more than 10% of
the valuation, not readily observable in the market. The modeled valuation
above represents the fair valuation of certain long-dated power
transactions based on limited observable broker prices extrapolated for
periods beyond two years into the
future.
Contractual Arrangements with Credit
Rating Triggers or Margining Rights
Under certain contractual arrangements
entered into by PHI’s subsidiaries in connection with Competitive Energy
business and other transactions, the subsidiary may be required to provide cash
collateral or letters of credit as security for its contractual obligations if
the credit ratings of the subsidiary are downgraded. In the event of
a downgrade, the amount required to be posted would depend on the amount of the
underlying contractual obligation existing at the time of the
downgrade. Based on contractual provisions in effect at December 31,2008, a one-level downgrade in the unsecured debt credit ratings of PHI and each
of its rated subsidiaries, which would decrease PHI’s rating to below
“investment grade,” would increase the collateral obligation of PHI and its
subsidiaries by up to $462 million. PHI believes that it and its
utility subsidiaries currently have sufficient liquidity to fund their
operations and meet their financial obligations.
Many of the contractual arrangements
entered into by PHI’s subsidiaries in connection with Competitive Energy and
Default Electricity Supply activities include margining rights pursuant to which
the PHI subsidiary or a counterparty may request collateral if the market value
of the contractual obligations reaches levels in excess of the credit thresholds
established in the applicable arrangements. Pursuant to these
margining rights, the affected PHI subsidiary may
93
PEPCO
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receive,
or be required to post, collateral due to energy price movements. As
of December 31, 2008, Pepco Holdings’ subsidiaries engaged in Competitive Energy
activities and Default Electricity Supply activities provided net cash
collateral in the amount of $365 million in connection with these
activities.
Environmental
Remediation Obligations
PHI’s accrued liabilities as of
December 31, 2008 include approximately $14 million, of which
$6 million is expected to be incurred in 2009, for potential environmental
cleanup and other costs related to sites at which an operating subsidiary is a
potentially responsible party, is alleged to be a third-party contributor, or
has made a decision to clean up contamination on its own
property. For information regarding projected expenditures for
environmental control facilities, see Item 1 “Business — Environmental Matters,”
of this Form 10-K. The most significant environmental remediation
obligations as of December 31, 2008, were:
·
$4 million,
of which $1 million is expected to be incurred in 2009, payable by
DPL in accordance with a 2001 consent agreement reached with the Delaware
Department of Natural Resources and Environmental Control, for
remediation, site restoration, natural resource damage compensatory
projects and other costs associated with environmental contamination that
resulted from an oil release at the Indian River power plant, which was
sold in June 2001.
·
$5 million
in environmental remediation costs, of which $1 million is expected
to be incurred in 2009, payable by Conectiv Energy associated with the
Deepwater generating
facility.
·
Less
than $1 million for environmental remediation costs related to former
manufactured gas plant operations at a Cambridge, Maryland site on
DPL-owned property, adjacent property and the adjacent Cambridge Creek,
all of which is expected to be incurred in
2009.
·
$2 million,
constituting Pepco’s liability for a remedy at the Metal Bank/Cottman
Avenue site.
·
$2 million,
most of which is expected to be incurred in 2009, payable by DPL in
connection with the Wilmington Coal Gas South site located in Wilmington,
Delaware, to remediate residual material from the historical operation of
a manufactured gas plant.
·
Less
than $1 million, of which a small portion is expected to be incurred in
2009, payable by Pepco for long-term monitoring associated with a pipeline
oil release that occurred in 2000.
Sources
of Capital
Pepco Holdings’ sources to meet its
long-term funding needs, such as capital expenditures, dividends, and new
investments, and its short-term funding needs, such as working capital and the
temporary funding of long-term funding needs, include internally generated
funds, securities issuances and bank financing under new or existing facilities.
PHI’s ability to
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PEPCO
HOLDINGS
generate
funds from its operations and to access capital and credit markets is subject to
risks and uncertainties. Volatile and deteriorating financial market
conditions, diminished liquidity and tightening credit may affect efficient
access to certain of PHI’s potential funding sources. See Item 1A,
“Risk Factors,” of this Form 10-K, for additional discussion of important
factors that may impact these sources of capital.
Internally Generated Cash
The primary source of Pepco Holdings’
internally generated funds is the cash flow generated by its regulated utility
subsidiaries in the Power Delivery business. Additional sources of
funds include cash flow generated from its non-regulated subsidiaries and the
sale of non-core assets.
Short-Term Funding Sources
Pepco
Holdings and its regulated utility subsidiaries have traditionally used a number
of sources to fulfill short-term funding needs, such as commercial paper,
short-term notes and bank lines of credit. Proceeds from short-term
borrowings are used primarily to meet working capital needs but may also be used
to fund temporarily long-term capital requirements.
Pepco Holdings maintains an ongoing
commercial paper program of up to $875 million. Pepco and DPL have
ongoing commercial paper programs of up to $500 million, and ACE up to
$250 million. The commercial paper can be issued with maturities
of up to 270 days. Due to the recent capital and credit market disruptions,
however, the market for commercial paper has been severely restricted for most
companies. As a result, PHI and its subsidiaries have not been able
to issue commercial paper on a day-to-day basis either in amounts or with
maturities that they have typically required for cash management
purposes.
A further description of the existence
and availability of the sources of short-term funding, and the impact of the
ongoing capital and credit market disruptions, is set forth above under the
headings “Impact of the Current Capital and Credit Market Disruptions —
Collateral Requirements of the Competitive Energy Businesses” and “Credit
Facilities.”
Long-Term Funding Sources
The sources of long-term funding for
PHI and its subsidiaries are the issuance of debt and equity securities and
borrowing under long-term credit agreements. Proceeds from long-term
financings are used primarily to fund long-term capital requirements, such as
capital expenditures and new investments, and to repay or refinance existing
indebtedness.
Regulatory
Restrictions on Financing Activities
The issuance of debt securities by
PHI’s principal subsidiaries requires approval of either FERC or one or more
state public utility commissions. Neither FERC approval nor state
public utility commission approval is required as a condition to the issuance of
securities by PHI.
State Financing Authority
Pepco’s long-term financing activities
(including the issuance of securities and the incurrence of debt) are subject to
authorization by the DCPSC and MPSC. DPL’s long-term financing
activities are subject to authorization by MPSC and the Delaware Public
Service
95
PEPCO
HOLDINGS
Commission
(DPSC). ACE’s long-term and short term (consisting of debt
instruments with a maturity of one year or less) financing activities are
subject to authorization by the NJBPU. Each utility, through periodic
filings with the state public service commission(s) having jurisdiction over its
financing activities, typically seeks to maintain standing authority sufficient
to cover its projected financing needs over a multi-year period.
FERC Financing Authority
Under the
Federal Power Act (FPA), FERC has jurisdiction over the issuance of long-term
and short-term securities of public utilities, but only if the issuance is not
regulated by the state public utility commission in which the public utility is
organized and operating. Under these provisions, FERC has
jurisdiction over the issuance of short-term debt by Pepco and
DPL. Pepco and DPL have obtained FERC authority for the issuance of
short-term debt. Because Conectiv Energy and Pepco Energy Services
also qualify as public utilities under the FPA and are not regulated by a state
utility commission, FERC also has jurisdiction over the issuance of securities
by those companies. Conectiv Energy and Pepco Energy Services have
obtained the requisite FERC financing authority in their respective market-based
rate orders.
Money Pool
Pepco Holdings operates a system money
pool, or an intra-system cash management program under a blanket authorization
adopted by FERC. The money pool is a cash management mechanism used
by Pepco Holdings to manage the short-term investment and borrowing requirements
of its subsidiaries that participate in the money pool. Pepco
Holdings may invest in but not borrow from the money pool. Eligible
subsidiaries with surplus cash may deposit those funds in the money
pool. Deposits in the money pool are guaranteed by Pepco
Holdings. Eligible subsidiaries with cash requirements may borrow
from the money pool. Borrowings from the money pool are
unsecured. Depositors in the money pool receive, and borrowers from
the money pool pay, an interest rate based primarily on Pepco Holdings’
short-term borrowing rate. Pepco Holdings deposits funds in the money
pool to the extent that the pool has insufficient funds to meet the borrowing
needs of its participants, which may require Pepco Holdings to borrow funds for
deposit from external sources.
REGULATORY
AND OTHER MATTERS
For a
discussion of material pending matters such as regulatory and legal proceedings,
and other commitments and contingencies, see Note (16), “Commitments and
Contingencies,” to the consolidated financial statements of PHI set forth in
Item 8 of this Form 10-K.
CRITICAL
ACCOUNTING POLICIES
General
Pepco Holdings has identified the
following accounting policies, including certain estimates, that as a result of
the judgments, uncertainties, uniqueness and complexities of the underlying
accounting standards and operations involved, could result in material changes
in its financial condition or results of operations under different conditions
or using different assumptions. Pepco Holdings has discussed the
development, selection and disclosure of each of these policies with the Audit
Committee of the Board of Directors.
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PEPCO
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Goodwill Impairment
Evaluation
PHI believes that the estimates
involved in its goodwill impairment evaluation process represent “Critical
Accounting Estimates” because they are subjective and susceptible to change from
period to period as management makes assumptions and judgments and the impact of
a change in assumptions could be material to financial results.
Substantially
all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002
and is allocated to the Power Delivery reporting unit for purposes of assessing
impairment under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No.
142). Management has identified Power Delivery as a single reporting
unit based on the aggregation of components. The first step of the
goodwill impairment test under SFAS No. 142 compares the fair value of the
reporting unit with its carrying amount, including
goodwill. Management uses its best judgment to make reasonable
projections of future cash flows for Power Delivery when estimating the
reporting unit’s fair value. In addition, PHI selects a discount rate
for the associated risk with those estimated cash flows. These
judgments are inherently uncertain, and actual results could vary from those
used in PHI’s estimates. The impact of such variations could
significantly alter the results of a goodwill impairment test, which could
materially impact the estimated fair value of Power Delivery and potentially the
amount of any impairment recorded in the financial statements.
PHI tests its goodwill for impairment
annually as of July 1, and whenever an event occurs or circumstances change
in the interim that would more likely than not reduce the fair value of a
reporting unit below its carrying amount. Factors that may result in
an interim impairment test include, but are not limited to: a change in
identified reporting units; an adverse change in business conditions; a
protracted decline in stock price causing market capitalization to fall below
book value; an adverse regulatory action; or impairment of long-lived assets in
the reporting unit.
PHI’s
July 1, 2008 annual impairment test indicated that its goodwill was not
impaired. PHI performed an interim test of goodwill for impairment at
December 31, 2008 as its market capitalization was below its book value for a
significant part of the fourth quarter of 2008, and it concluded that its
goodwill was not impaired. Details about the interim test at year-end
and the results are included in Note (6), “Goodwill,” in PHI’s consolidated
financial statements in Item 8 of this Form 10-K.
In order
to estimate the fair value of the Power Delivery reporting unit, PHI reviews the
results from two discounted cash flow models. The models differ in
the method used to calculate the terminal value of the reporting
unit. One estimate of terminal value is based on a constant, annual
cash flow growth rate that is consistent with Power Delivery’s plan, and the
other estimate of terminal value is based on a multiple of earnings before
interest, taxes, depreciation, and amortization that management believes is
consistent with relevant market multiples for comparable utilities. Each
model uses a cost of capital appropriate for a regulated utility as the discount
rate for the estimated cash flows associated with the reporting
unit. Neither valuation model evidenced impairment of
goodwill. PHI has consistently used this valuation model to estimate
the fair value of Power Delivery since the adoption of SFAS No.
142.
The
estimation of fair value is dependent on a number of factors, including but not
limited to interest rates, growth assumptions, assumptions about regulatory
ratemaking
97
PEPCO
HOLDINGS
proceedings,
operating and capital expenditure requirements and other factors, changes in
which could materially impact the results of impairment
testing. Assumptions and methodologies used in the models were
consistent with historical experience. A hypothetical 10 percent
decrease in fair value of the Power Delivery reporting unit at December 31, 2008
would not have resulted in the Power Delivery reporting unit failing the first
step of the impairment test as defined in SFAS No. 142. Sensitive,
interrelated and uncertain variables that could decrease the estimated fair
value of the Power Delivery reporting unit include utility sector market
performance, sustained adverse business conditions, the results of rate-making
proceedings, higher operating and capital expenditure requirements, a
significant increase in the cost of capital and other factors.
Long-Lived Assets Impairment
Evaluation
Pepco Holdings believes that the
estimates involved in its long-lived asset impairment evaluation process
represent “Critical Accounting Estimates” because (i) they are highly
susceptible to change from period to period because management is required to
make assumptions and judgments about undiscounted and discounted future cash
flows and fair values, which are inherently uncertain, (ii) actual results could
vary from those used in Pepco Holdings’ estimates and the impact of such
variations could be material, and (iii) the impact that recognizing an
impairment would have on Pepco Holdings’ assets as well as the net loss related
to an impairment charge could be material.
SFAS No. 144, “Accounting for the
Impairment or Disposal of Long-Lived Assets,” requires that certain long-lived
assets must be tested for recoverability whenever events or circumstances
indicate that the carrying amount may not be recoverable. An
impairment loss may only be recognized if the carrying amount of an asset is not
recoverable and the carrying amount exceeds its fair value. The asset is deemed
not to be recoverable when its carrying amount exceeds the sum of the
undiscounted future cash flows expected to result from the use and eventual
disposition of the asset. In order to estimate an asset’s future cash flows,
Pepco Holdings considers historical cash flows. Pepco Holdings uses
its best estimates in making these evaluations and considers various factors,
including forward price curves for energy, fuel costs, legislative initiatives,
and operating costs. If necessary, the process of determining fair
value is done consistent with the process described in assessing the fair value
of goodwill discussed above.
Accounting for Derivatives
Pepco Holdings believes that the
estimates involved in accounting for its derivative instruments represent
“Critical Accounting Estimates” because (i) the fair value of the instruments
are highly susceptible to changes in market value and/or interest rate
fluctuations, (ii) there are significant uncertainties in modeling techniques
used to measure fair value in certain circumstances, (iii) actual results could
vary from those used in Pepco Holdings’ estimates and the impact of such
variations could be material, and (iv) changes in fair values and market prices
could result in material impacts to Pepco Holdings’ assets, liabilities, other
comprehensive income (loss), and results of operations. See Note (2),
“Significant Accounting Policies ¾ Accounting for
Derivatives,” to the consolidated financial statements of PHI set forth in Item
8 of this Form 10-K for information on PHI’s accounting for
derivatives.
Pepco Holdings and its subsidiaries use
derivative instruments primarily to manage risk associated with commodity prices
and interest rates. SFAS No. 133, “Accounting for
Derivative
98
PEPCO
HOLDINGS
Instruments
and Hedging Activities,” as amended, governs
the accounting treatment for derivatives and requires that derivative
instruments be measured at fair value. The fair value of derivatives
is determined using quoted exchange prices where available. For
instruments that are not traded on an exchange, external broker quotes are used
to determine fair value. For some custom and complex instruments,
internal models are used to interpolate broker quality price
information. For certain long-dated instruments, broker or exchange
data is extrapolated for future periods where limited market information is
available. Models are also used to estimate volumes for certain
transactions. The
same valuation methods are used to determine the value of non-derivative,
commodity exposure for risk management purposes.
Pension and Other Postretirement
Benefit Plans
Pepco
Holdings believes that the estimates involved in reporting the costs of
providing pension and other postretirement benefits represent “Critical
Accounting Estimates” because (i) they are based on an actuarial calculation
that includes a number of assumptions which are subjective in nature, (ii) they
are dependent on numerous factors resulting from actual plan experience and
assumptions of future experience, and (iii) changes in assumptions could impact
Pepco Holdings’ expected future cash funding requirements for the plans and
would have an impact on the projected benefit obligations, and the reported
annual net periodic pension and other postretirement benefit cost on the income
statement.
Assumptions about the future, including
the expected return on plan assets, discount rate applied to benefit
obligations, the anticipated rate of increase in health care costs and
participant compensation have a significant impact on employee benefit costs. In
terms of quantifying the anticipated impact of a change in the critical
assumptions while holding all other assumptions constant, Pepco Holdings
estimates that a .25% decrease in the discount rate used to value the benefit
obligations could result in a $7 million increase in net periodic benefit
cost. Additionally, Pepco Holdings estimates that a .25%
reduction in the expected return on plan assets could result in a $6
million increase in net periodic benefit cost. A 1.0% increase in the assumed
healthcare cost trend rate could result in a $2 million increase net periodic
benefit cost. In addition to its impact on cost, a .25% decrease
in the discount rate would increase PHI’s projected pension benefit obligation
by $60 million and would increase the accumulated postretirement benefit
obligation by $18 million at December 31, 2008. Pepco Holdings’ management
consults with its actuaries and investment consultants when selecting its plan
assumptions, and benchmarks its critical assumptions against other corporate
plans.
The impact of changes in assumptions
and the difference between actual and expected or estimated results on pension
and postretirement obligations is generally recognized over the working lives of
the employees who benefit under the plans rather than immediately recognized in
the statements of earnings.
For additional discussion, see
Note (10), “Pensions and Other Postretirement Benefits,” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K.
Regulation of Power Delivery
Operations
The requirements of SFAS No. 71,
“Accounting for the Effects of Certain Types of Regulation,” apply to the Power
Delivery businesses of Pepco, DPL, and ACE. Pepco Holdings believes that the
judgment involved in accounting for its regulated activities
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PEPCO
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represent
“Critical Accounting Estimates” because (i) a significant amount of judgment is
required (including but not limited to the interpretation of laws and regulatory
commission orders) to assess the probability of the recovery of regulatory
assets, (ii) actual results and interpretations could vary from those used in
Pepco Holdings’ estimates and the impact of such variations could be material,
and (iii) the impact that writing off a regulatory asset would have on Pepco
Holdings’ assets and the net loss related to the charge could be
material.
Unbilled Revenue
Unbilled revenue represents an estimate
of revenue earned from services rendered by Pepco Holdings’ utility operations
that have not yet been billed. Pepco Holdings’ utility operations
calculate unbilled revenue using an output based methodology. This
methodology is based on the supply of electricity or gas distributed to
customers. Pepco Holdings believes that the estimates involved in its
unbilled revenue process represent “Critical Accounting Estimates” because
management is required to make assumptions and judgments about input factors
such as customer sales mix and estimated power line losses (estimates of
electricity expected to be lost in the process of its transmission and
distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, the impact of which could be
material.
Accounting for Income
Taxes
Pepco Holdings and the majority of its
subsidiaries file a consolidated federal income tax return. Pepco Holdings
accounts for income taxes in accordance with SFAS No. 109, “Accounting for
Income Taxes,” and effective January 1, 2007, adopted FIN 48 “Accounting for
Uncertainty in Income Taxes.” FIN 48 clarifies the criteria for
recognition of tax benefits in accordance with SFAS No. 109, and prescribes a
financial statement recognition threshold and measurement attribute for a tax
position taken or expected to be taken in a tax return. Specifically,
it clarifies that an entity’s tax benefits must be “more likely than not” of
being sustained assuming that position will be examined by taxing authorities
with full knowledge of all relevant information prior to recording
the related tax benefit in the financial statements. If the position
drops below the “more likely than not” standard, the benefit can no longer be
recognized.
Assumptions, judgment and the use of
estimates are required in determining if the “more likely than not” standard has
been met when developing the provision for income taxes. Pepco
Holdings’ assumptions, judgments and estimates take into account current tax
laws, interpretation of current tax laws and the possible outcomes of current
and future investigations conducted by tax authorities. Pepco
Holdings has established reserves for income taxes to address potential
exposures involving tax positions that could be challenged by tax
authorities. Although Pepco Holdings believes that these assumptions,
judgments and estimates are reasonable, changes in tax laws or its
interpretation of tax laws and the resolutions of the current and any future
investigations could significantly impact the amounts provided for income taxes
in the consolidated financial statements.
Under SFAS No. 109, deferred income tax
assets and liabilities are recorded, representing future effects on income taxes
for temporary differences between the bases of assets and liabilities for
financial reporting and tax purposes. Pepco Holdings evaluates quarterly the
probability of realizing deferred tax assets by reviewing a forecast of future
taxable income and
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PEPCO
HOLDINGS
the
availability of tax planning strategies that can be implemented, if necessary,
to realize deferred tax assets. Failure to achieve forecasted taxable income or
successfully implement tax planning strategies may affect the realization of
deferred tax assets.
New
Accounting Standards and Pronouncements
For information concerning new
accounting standards and pronouncements that have recently been adopted by PHI
and its subsidiaries or that one or more of the companies will be required to
adopt on or before a specified date in the future, see Note (3), “Newly Adopted
Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not
Yet Adopted,” to the consolidated financial statements of PHI set forth in Item
8 of this Form 10-K.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding Pepco
Holdings’ intents, beliefs and current expectations. In some cases, you can
identify forward-looking statements by terminology such as “may,”“will,”“should,”“expects,”“plans,”“anticipates,”“believes,”“estimates,”“predicts,”“potential” or “continue” or the negative of such terms or other
comparable terminology. Any forward-looking statements are not guarantees of
future performance, and actual results could differ materially from those
indicated by the forward-looking statements. Forward-looking statements involve
estimates, assumptions, known and unknown risks, uncertainties and other factors
that may cause PHI’s actual results, levels of activity, performance or
achievements to be materially different from any future results, levels of
activity, performance or achievements expressed or implied by such
forward-looking statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond Pepco Holdings’ control and may cause actual results to differ materially
from those contained in forward-looking statements:
·
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
·
Changes
in and compliance with environmental and safety laws and
policies;
·
Weather
conditions;
·
Population
growth rates and demographic
patterns;
·
Competition
for retail and wholesale customers;
·
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
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PEPCO
HOLDINGS
·
Growth
in demand, sales and capacity to fulfill
demand;
·
Changes
in tax rates or policies or in rates of
inflation;
·
Changes
in accounting standards or
practices;
·
Changes
in project costs;
·
Unanticipated
changes in operating expenses and capital
expenditures;
·
The
ability to obtain funding in the capital markets on favorable
terms;
·
Rules
and regulations imposed by federal and/or state regulatory commissions,
PJM and other regional transmission organizations (New York Independent
System Operator, ISONE), the North American Electric Reliability Council
and other applicable electric reliability
organizations;
·
Legal
and administrative proceedings (whether civil or criminal) and settlements
that affect PHI’s business and
profitability;
·
Pace
of entry into new markets;
·
Volatility
in market demand and prices for energy, capacity and
fuel;
·
Interest
rate fluctuations and credit and capital market conditions;
and
·
Effects
of geopolitical events, including the threat of domestic
terrorism.
Any forward-looking statements speak
only as to the date of this Annual Report and Pepco Holdings undertakes no
obligation to update any forward-looking statements to reflect events or
circumstances after the date on which such statements are made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time, and it
is not possible for Pepco Holdings to predict all of such factors, nor can Pepco
Holdings assess the impact of any such factor on Pepco Holding’s business or the
extent to which any factor, or combination of factors, may cause results to
differ materially from those contained in any forward-looking
statement.
The foregoing review of factors should
not be construed as exhaustive.
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103
PEPCO
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
POTOMAC
ELECTRIC POWER COMPANY
GENERAL
OVERVIEW
Potomac Electric Power Company (Pepco)
is engaged in the transmission and distribution of electricity in Washington,
D.C. and major portions of Montgomery County and Prince George’s County in
suburban Maryland. Pepco provides Default Electricity Supply, which
is the supply of electricity at regulated rates to retail customers in its
territories who do not elect to purchase electricity from a competitive
supplier, in both the District of Columbia and Maryland. Default
Electricity Supply is known as Standard Offer Service in both the District of
Columbia and Maryland. Pepco’s service territory covers approximately
640 square miles and has a population of approximately 2.1
million. As of December 31, 2008, approximately 57% of delivered
electricity sales were to Maryland customers and approximately 43% were to
Washington, D.C. customers.
In connection with its approval of new
electric service distribution base rates for Pepco in Maryland, effective in
June, 2007 (the 2007 Maryland Rate Order), the Maryland Public Service
Commission (MPSC) approved a bill stabilization adjustment mechanism (BSA) for
retail customers. For customers to which the BSA applies, Pepco
recognizes distribution revenue based on an approved distribution charge per
customer. From a revenue recognition standpoint, the BSA thus
decouples the distribution revenue recognized in a reporting period from the
amount of power delivered during the period. This change in the
reporting of distribution revenue has the effect of eliminating changes in
retail 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 from retail customers in Maryland to fluctuate from period
to period are changes in the number of customers and changes in the approved
distribution charge per customer.
Pepco is a wholly owned subsidiary of
Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public
utility holding company subject to the Public Utility Holding Company Act of
2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities
of Pepco are subject to the regulatory oversight of Federal Energy Regulatory
Commission under PUHCA 2005.
IMPACT
OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The
recent disruptions in the capital and credit markets have had an impact on
Pepco’s business. While these conditions have required Pepco to make
certain adjustments in its financial management activities, Pepco believes that
it currently has sufficient liquidity to fund its operations and meet its
financial obligations. These market conditions, should they continue,
however, could have a negative effect on Pepco’s financial condition, results of
operations and cash flows.
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PEPCO
Liquidity
Requirements
Pepco depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, Pepco historically has relied on the issuance
of commercial paper and short-term notes and on bank lines of credit to
supplement internally generated cash from operations. Pepco’s primary
credit source is PHI’s $1.5 billion syndicated credit facility, under which
Pepco can borrow funds, obtain letters of credit and support the issuance of
commercial paper in an amount up to $500 million (subject to the limitation that
the total utilization by Pepco and PHI’s other utility subsidiaries cannot
exceed $625 million). This facility is in effect until May 2012 and
consists of commitments from 17 lenders, no one of which is responsible for more
than 8.5% of the total commitment.
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, Pepco has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. Given its
restricted access to the commercial paper market and the uncertainty in the
credit markets generally, Pepco borrowed $100 million under the credit facility
to create a cash reserve for future short-term operating needs at December 31,2008. After giving effect to outstanding letters of credit and
commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million
in combined cash and borrowing capacity under the credit facility at December31, 2008. During the months of January and February 2009, the average
daily amount of the combined cash and borrowing capacity of PHI’s utility
subsidiaries was $831 million and ranged from a low of $673 million to a high of
$1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, Pepco
has identified a number of cash and liquidity conservation measures, including
opportunities to defer capital expenditures due to lower than anticipated
growth. Several measures to reduce expenditures have been
taken. Additional measures could be undertaken if conditions
warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, Pepco issued $250 million
in long-term debt securities in December, with the proceeds used to refund
short-term debt incurred to finance utility construction and operations on a
temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
Pepco participates in pension and
postretirement benefit plans sponsored by PHI for its
employees. While the plans have not experienced any significant
impact in terms of liquidity or counterparty exposure due to the disruption of
the capital and credit markets, the recent stock market declines have caused a
decrease in the market value of benefit plan assets in 2008. Pepco
expects to contribute approximately $170 million to the pension plan in
2009.
105
PEPCO
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2008 to the year ended
December 31, 2007. Other than this disclosure, information under this
item has been omitted in accordance with General Instruction I(2)(a) to the Form
10-K. All amounts in the tables (except sales and customers) are in
millions of dollars.
Operating
Revenue
2008
2007
Change
Regulated
T&D Electric Revenue
$
978
$
928
$
50
Default
Supply Revenue
1,309
1,241
68
Other
Electric Revenue
35
32
3
Total
Operating Revenue
$
2,322
$
2,201
$
121
The table above shows the amount of
Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
includes revenue from the delivery of electricity, including the delivery of
Default Electricity Supply, to Pepco’s customers within its service territory at
regulated rates. Regulated T&D Electric Revenue also includes
transmission service revenue that Pepco receives as a transmission owner from
PJM Interconnection, LLC (PJM).
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.
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is not subject to price regulation. Work and services includes mutual
assistance to other utilities, highway relocation, rentals of pole attachments,
late payment fees, and collection fees.
Regulated T&D Electric
Regulated
T&D Electric Revenue
2008
2007
Change
Residential
$
259
$
263
$
(4)
Commercial
544
529
15
Industrial
-
-
-
Other
175
136
39
Total
Regulated T&D Electric Revenue
$
978
$
928
$
50
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue, (ii) revenue
from the resale of energy and capacity under power purchase agreements between
Pepco and unaffiliated third parties in the PJM Regional Transmission
Organization (PJM RTO) market, and (iii) either (a) a positive adjustment equal
to the amount by which revenue from Maryland retail distribution sales falls
short of the revenue that Pepco is entitled to earn based on the distribution
charge per customer approved in the 2007 Maryland Rate Order or
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PEPCO
(b) a
negative adjustment equal to the amount by which revenue from such distribution
sales exceeds the revenue that Pepco is entitled to earn based on the approved
distribution charge per customer (a Revenue Decoupling Adjustment).
Regulated
T&D Electric Sales (Gigawatt hours(GWh))
2008
2007
Change
Residential
7,730
8,093
(363)
Commercial
18,972
19,197
(225)
Industrial
-
-
-
Other
161
161
-
Total
Regulated T&D Electric Sales
26,863
27,451
(588)
Regulated
T&D Electric Customers (in thousands)
2008
2007
Change
Residential
693
687
6
Commercial
74
73
1
Industrial
-
-
-
Other
-
-
-
Total
Regulated T&D Electric Customers
767
760
7
Regulated T&D Electric Revenue increased by $50 million primarily due
to:
·
An
increase of $24 million 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).
·
An
increase of $24 million due to a distribution rate change in the District
of Columbia that became effective in February
2008.
·
An
increase of $16 million due to a distribution rate change under the 2007
Maryland Rate Order that became effective in June 2007, including a
positive $13 million Revenue Decoupling
Adjustment.
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $11 million due to lower weather-related sales (a 4% decrease
in Heating Degree Days and a 6% decrease in Cooling Degree
Days).
·
A
decrease of $6 million due to differences in consumption among the various
customer rate classes.
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PEPCO
Default Electricity Supply
Default
Supply Revenue
2008
2007
Change
Residential
$
804
$
774
$
30
Commercial
498
459
39
Industrial
-
-
-
Other
7
8
(1)
Total
Default Supply Revenue
$
1,309
$
1,241
$
68
Default
Electricity Supply Sales (GWh)
2008
2007
Change
Residential
7,310
7,692
(382)
Commercial
4,126
4,384
(258)
Industrial
-
-
-
Other
9
37
(28)
Total
Default Electricity Supply Sales
11,445
12,113
(668)
Default
Electricity Supply Customers (in thousands)
2008
2007
Change
Residential
660
659
1
Commercial
53
52
1
Industrial
-
-
-
Other
-
-
-
Total
Default Electricity Supply Customers
713
711
2
Default Supply Revenue, which is
substantially offset in Fuel and Purchased Energy, increased by $68 million
primarily due to:
·
An
increase of $126 million in market-based Default Electricity Supply
rates.
The
increase was partially offset by:
·
A
decrease of $27 million due to lower weather-related sales (a 4% decrease
in Heating Degree Days and a 6% decrease in Cooling Degree
Days).
·
A
decrease of $22 million primarily due to existing commercial customers
electing to purchase electricity from competitive
suppliers.
·
A
decrease of $10 million primarily due to differences in consumption among
the various customer rate classes.
The following table shows the
percentages of Pepco’s total distribution sales by jurisdiction that are derived
from customers receiving Default Electricity Supply from Pepco.
2008
2007
Sales
to District of Columbia customers
33%
35%
Sales
to Maryland customers
50%
51%
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PEPCO
Operating
Expenses
Fuel
and Purchased Energy
Fuel and
Purchased Energy, which is primarily associated with Default Electricity Supply
revenue, increased by $89 million to $1,335 million in 2008 from $1,246 million
in 2007. The increase was primarily due to the
following:
·
An
increase of $138 million in average energy costs, the result of new
Default Electricity Supply
contracts.
·
An
increase of $24 million for energy and capacity purchased under the Panda
PPA.
The
aggregate amount of these increases was partially offset
by:
·
A
decrease of $39 million primarily due to commercial customers electing to
purchase electricity from competitive
suppliers.
·
A
decrease of $29 million due to lower weather-related
sales.
Fuel and
Purchased Energy expense is substantially offset in Regulated T&D Electric
Revenue and Default Supply Revenue.
Other
Operation and Maintenance
Other
Operation and Maintenance increased by $2 million to $302 million in 2008 from
$300 million in 2007. The increase was primarily due to the
following:
·
An
increase of $7 million in deferred administrative expenses associated with
Default Electricity Supply (offset in Default Supply Revenue) as the
result of the inclusion of $5 million of customer late payment fees in the
calculation of the deferral. See the discussion below regarding
the 2008 correction of an error in recording customer late payment fees,
including $3 million related to prior
periods.
·
An
increase of $3 million due to higher bad debt expenses associated with
distribution and Default Electricity Supply customers, of which
approximately $1 million was
deferred.
·
An
increase of $3 million in employee-related costs primarily due to the
recording of additional stock-based compensation expense as discussed
below, including $3 million related to prior
periods.
·
An
increase of $1 million in legal
expenses.
·
An
increase of $1 million in environmental costs related to spill prevention
and waste disposal.
109
The
aggregate amount of these increases was partially offset
by:
·
A
decrease of $5 million in corrective and preventative maintenance
costs.
·
A
decrease of $4 million in regulatory expenses primarily related to the
District of Columbia distribution rate case in
2007.
·
A
decrease of $3 million due to various construction project write-offs in
2007 related to customer requested
work.
·
A
decrease of $3 million in accounting fees related to tax consulting
services.
During
2008, Pepco recorded adjustments to correct errors in Other Operation and
Maintenance expenses for prior periods dating back to February 2005 during which
(i) customer late payment fees were incorrectly recognized and (ii) stock-based
compensation expense related to certain restricted stock awards granted under
the Long-Term Incentive Plan was understated. These adjustments resulted in a
total increase in Other Operation and Maintenance expenses for the year ended
December 31, 2008 of $6 million.
Depreciation and
Amortization
Depreciation and Amortization expenses
decreased by $10 million to $141 million in 2008, from $151 million in
2007. The decrease was primarily due to a change in depreciation
rates in accordance with the 2007 Maryland Rate Order.
Effect of Settlement of Mirant
Bankruptcy Claims
The Effect of Settlement of Mirant
Bankruptcy Claims reflects the recovery in 2007 of $33 million in operating
expenses and certain other costs as damages in the Mirant Corporation (Mirant)
bankruptcy settlement.
Other
Income (Expenses)
Other
Expenses (which are net of Other Income) increased by $15 million to a net
expense of $76 million in 2008 from a net expense of $61 million in 2007. This
increase was primarily due to:
·
An
increase of $12 million in interest expense due to higher outstanding
long-term debt during 2008.
·
A
decrease of $2 million in Contribution in Aid of Construction tax gross-up
income.
Income
Tax Expense
Pepco’s effective tax rates for the
years ended December 31, 2008 and 2007 were 35.6% and 33.2%,
respectively. While the change in the effective rate between 2008 and
2007 was not significant, the effective rate in each year was impacted by
certain non-recurring items. In 2008, Pepco recorded certain tax
benefits that reduced its overall effective tax rate, including net interest
income accrued on the tentative settlement with the IRS on the mixed service
cost issue
110
PEPCO
discussed
below, interest income accrued on other effectively settled and uncertain tax
positions, interest income received in 2008 on the Maryland state tax refund
referred to below, and deferred tax adjustments related to additional analysis
of its deferred tax balances completed in 2008. In 2007, Pepco
recorded the receipt of the Maryland state tax refund in the third quarter of
2007 as a reduction in income tax expense. This benefit was partially
offset by certain income tax charges recorded in the third quarter of 2007
related to additional analysis of Pepco’s deferred tax balances.
During
the second quarter 2008, Pepco reached a tentative settlement with the Internal
Revenue Service (IRS) concerning the treatment of mixed service costs for income
tax purposes during the period 2001 to 2004. On the basis of the
tentative settlement, Pepco updated its estimated liability related to mixed
service costs and, as a result, recorded a net reduction in its liability for
unrecognized tax benefits of $16 million and recognized after-tax interest
income of $3 million in the second quarter of 2008. See Note
(13), “Commitments and Contingencies — Regulatory and Other Matters —
IRS Mixed Service Cost Issue,” to the financial statements of Pepco set forth in
Item 8 of this Form 10-K.
Capital
Requirements
Capital
Expenditures
Pepco’s total capital expenditures for
the year ended December 31, 2008, totaled $275 million. These
expenditures were primarily related to capital costs associated with new
customer services, distribution reliability and transmission.
The table below shows Pepco’s projected
capital expenditures for the five year period 2009 through 2013:
For
the Year
2009
2010
2011
2012
2013
Total
(Millions
of Dollars)
Pepco
Distribution
$
206
$
207
$
221
$
267
$
302
$
1,203
Distribution
- Blueprint for the Future
11
16
3
72
79
181
Transmission
52
112
157
94
49
464
Transmission
- Mid-Atlantic Power Pathway (MAPP)
46
99
182
128
60
515
Other
12
15
25
26
15
93
$
327
$
449
$
588
$
587
$
505
$
2,456
Pepco expects to fund these
expenditures through internally generated cash and from external financing and
capital contributions from PHI.
As
further discussed in Note (10), “Debt” to the Pepco financial statements set
forth in Item 8 of this Form 10-K, PHI, Pepco, Delmarva Power & Light
Company (DPL) and Atlantic City Electric Company (ACE) maintain credit
facilities to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under the facilities is $1.9
billion. The primary facility consists of a $1.5 billion facility
which expires in 2012, all or any portion of which may be used to obtain loans
or to issue letters of credit. PHI’s credit limit under the facility is $875
million. The credit limit of Pepco is the lesser of $500 million and the maximum
amount of debt the company is permitted to have outstanding by its regulatory
authorities which is $500 million,
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PEPCO
except
that the aggregate amount of credit used by Pepco, DPL and ACE at any given time
collectively may not exceed $625 million.
Distribution and Transmission
The
projected capital expenditures listed in the table for distribution (other than
Blueprint for the Future) and transmission (other than MAPP) are primarily for
facility replacements and upgrades to accommodate customer growth and
reliability.
Blueprint for the Future
During 2007, Pepco announced an
initiative it refers to as the “Blueprint for the Future.” The
initiative combines traditional energy efficiency programs with new technologies
and systems to help customers manage their energy use and reduce the total cost
of energy. Pepco has made filings with the District of Columbia
Public Service Commission (DCPSC) and the MPSC for approval of certain aspects
of these programs. On December 18, 2008, the DCPSC conditionally
approved five DSM programs. The cost of these programs will be
recovered through a rate surcharge. On December 31, 2008, the MPSC
conditionally approved for both Pepco and DPL, four residential and four
non-residential DSM/energy efficiency programs. The MPSC will
consider an Advanced Metering Infrastructure program in a separate
proceeding. Pepco anticipates that the costs of these programs will
be recovered through a previously approved surcharge mechanism.
MAPP Project
In October 2007, the PJM Board of
Managers approved PHI’s proposed MAPP transmission project for construction of a
new 230-mile, 500-kilovolt interstate transmission project at a then-estimated
cost of $1 billion. This MAPP project will originate at Possum Point
substation in northern Virginia, connect into three substations across southern
Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva
Peninsula and terminate at Salem substation in southern New
Jersey. This MAPP project is part of PJM’s Regional Transmission
Expansion Plan required to address the reliability objectives of the PJM RTO
system. On December 4, 2008, the PJM Board approved a direct-current
technology for segments of the project including the Chesapeake Bay
Crossing. With this modification, the cost of the MAPP project
currently is estimated at $1.4 billion. PJM has determined that the
line segment from Possum Point substation to the second substation on the
Delmarva Peninsula (Indian River substation) is required to be operational by
June 1, 2013. PJM is continuing to evaluate the in-service date for
the remaining 80-miles of line segment to connect the Indian River substation to
the Salem substation. Construction is expected to occur in stages over the
next five year period.
Proceeds from Settlement of Mirant
Bankruptcy Claims
On September 5, 2008, Pepco
transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a
payment to Sempra, terminating all further rights, obligations and liabilities
of Pepco under the Panda PPA. The use of the damages received from
Mirant to offset above-market costs of energy and capacity under the Panda PPA
and to make the payment to Sempra reduced the balance of proceeds from the
Mirant settlement to approximately $102 million as of December 31,2008.
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PEPCO
In November 2008, Pepco filed with the
DCPSC and the MPSC proposals to share with customers the remaining balance of
proceeds from the Mirant settlement in accordance with divestiture sharing
formulas previously approved by the respective commissions. Under
Pepco’s proposals, District of Columbia and Maryland customers would receive a
total of approximately $25 million and $29 million,
respectively. On December 12, 2008, the DCPSC issued a Notice of
Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds,
including the bankruptcy settlement proceeds. The public comment
period for the proposed rules has expired without any comments being
submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the
Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed
a settlement agreement with the MPSC. The settlement, among other
things, provides that of the remaining balance of the Mirant settlement, Pepco
shall distribute $39 million to its Maryland customers through a one-time
billing credit. If the settlement is approved by the MPSC, Pepco
currently estimates that it will result in a pre-tax gain in the range of $15
million to $20 million, which will be recorded when the MPSC issues its final
order approving the settlement.
Pending the final disposition of these
funds, the remaining $102 million in proceeds from the Mirant settlement is
being accounted for as restricted cash and as a regulatory
liability.
FORWARD-LOOKING STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding
Pepco’s intents, beliefs and current expectations. In some cases, you
can identify forward-looking statements by terminology such as “may,”“will,”“should,”“expects,”“plans,”“anticipates,”“believes,”“estimates,”“predicts,”“potential” or “continue” or the negative of such terms or other
comparable terminology. Any forward-looking statements are not
guarantees of future performance, and actual results could differ materially
from those indicated by the forward-looking
statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause Pepco’s actual results, levels of activity, performance or achievements to
be materially different from any future results, levels of activity, performance
or achievements expressed or implied by such forward-looking
statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond Pepco’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
·
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
·
Changes
in and compliance with environmental and safety laws and
policies;
113
PEPCO
·
Weather
conditions;
·
Population
growth rates and demographic
patterns;
·
Competition
for retail and wholesale customers;
·
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
·
Growth
in demand, sales and capacity to fulfill
demand;
·
Changes
in tax rates or policies or in rates of
inflation;
·
Changes
in accounting standards or
practices;
·
Changes
in project costs;
·
Unanticipated
changes in operating expenses and capital
expenditures;
·
The
ability to obtain funding in the capital markets on favorable
terms;
·
Rules
and regulations imposed by federal and/or state regulatory commissions,
PJM, the North American Electric Reliability Council and other applicable
electric reliability organizations;
·
Legal
and administrative proceedings (whether civil or criminal) and settlements
that influence Pepco’s business and
profitability;
·
Volatility
in market demand and prices for energy, capacity and
fuel;
·
Interest
rate fluctuations and credit and capital market conditions;
and
·
Effects
of geopolitical events, including the threat of domestic
terrorism.
Any forward-looking statements speak
only as to the date of this Annual Report and Pepco undertakes no obligation to
update any forward-looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it is not
possible for Pepco to predict all of such factors, nor can Pepco assess the
impact of any such factor on Pepco’s business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
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PAGE LEFT INTENTIONALLY BLANK.
115
DPL
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
DELMARVA
POWER & LIGHT COMPANY
GENERAL
OVERVIEW
Delmarva Power & Light Company
(DPL) is engaged in the transmission and distribution of electricity in Delaware
and portions of Maryland. DPL provides Default Electricity Supply,
which is the supply of electricity at regulated rates to retail customers in its
territories who do not elect to purchase electricity from a competitive
supplier. Default Electricity Supply is also known as Standard Offer
Service in Maryland and in Delaware. DPL’s electricity distribution
service territory covers approximately 5,000 square miles and has a population
of approximately 1.3 million. As of December 31, 2008, approximately
67% of delivered electricity sales were to Delaware customers and approximately
33% were to Maryland customers. In northern Delaware, DPL also
supplies and distributes natural gas to retail customers and provides
transportation-only services to retail customers that purchase natural gas from
other suppliers. DPL’s
natural gas distribution service territory covers approximately 275 square miles
and has a population of approximately 500,000.
Effective January 2, 2008, DPL sold its
retail electric distribution assets and its wholesale electric transmission
assets in Virginia. Prior to that date, DPL supplied electricity at
regulated rates to retail customers in its service territory who did not elect
to purchase electricity from a competitive energy supplier, which is referred to
in Virginia as Default Service.
In
connection with its approval of new electric service distribution base rates for
DPL in Maryland, effective in June, 2007 (the 2007 Maryland Rate Order), the
Maryland Public Service Commission (MPSC) approved a bill stabilization
adjustment mechanism (BSA) for retail customers. For customers to
which the BSA applies, DPL recognizes distribution revenue based on an approved
distribution charge per customer. From a revenue recognition
standpoint, the BSA thus decouples the distribution revenue recognized in a
reporting period from the amount of power delivered during the
period. This change in the reporting of distribution revenue has the
effect of eliminating changes in retail 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 from retail customers in
Maryland to fluctuate from period to period are changes in the number of
customers and changes in the approved distribution charge per
customer.
DPL is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco
Holdings). Because PHI is a public utility holding company subject to
the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship
between PHI and DPL and certain activities of DPL are subject to the regulatory
oversight of Federal Energy Regulatory Commission under PUHCA 2005.
IMPACT
OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The
recent disruptions in the capital and credit markets have had an impact on DPL’s
business. While these conditions have required DPL to make certain
adjustments in its financial
116
DPL
management
activities, DPL believes that it currently has sufficient liquidity to fund its
operations and meet its financial obligations. These market
conditions, should they continue, however, could have a negative effect on DPL’s
financial condition, results of operations and cash flows.
Liquidity
Requirements
DPL depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, DPL historically has relied on the issuance of
commercial paper and short-term notes and on bank lines of credit to supplement
internally generated cash from operations. DPL’s primary credit
source is PHI’s $1.5 billion syndicated credit facility, under which DPL can
borrow funds, obtain letters of credit and support the issuance of commercial
paper in an amount up to $500 million (subject to the limitation that the total
utilization by DPL and PHI’s other utility subsidiaries cannot exceed $625
million). This facility is in effect until May 2012 and consists of
commitments from 17 lenders, no one of which is responsible for more than 8.5%
of the total commitment.
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, DPL has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. After giving effect to
outstanding letters of credit and commercial paper, PHI’s utility subsidiaries
have an aggregate of $843 million in combined cash and borrowing capacity under
the credit facility at December 31, 2008. During the months of
January and February 2009, the average daily amount of the combined cash and
borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged
from a low of $673 million to a high of $1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, DPL has
identified a number of cash and liquidity conservation measures, including
opportunities to defer capital expenditures due to lower than anticipated
growth. Several measures to reduce expenditures have been
taken. Additional measures could be undertaken if conditions
warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, DPL issued $250 million in
long-term debt securities in November, with the proceeds used to refund
short-term debt incurred to finance utility construction and operations on a
temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
DPL participates in several of the
pension and postretirement benefit plans sponsored by PHI and its subsidiaries
for their employees. While the plans have not experienced any
significant impact in terms of liquidity or counterparty exposure due to the
disruption of the capital and credit markets, the recent stock market declines
have caused a decrease in the market value of benefit plan assets in 2008. DPL
expects to contribute approximately $10 million to the pension plan in
2009.
117
DPL
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2008 to the year ended
December 31, 2007. Other than this disclosure, information under this
item has been omitted in accordance with General Instruction I(2)(a) to the Form
10-K. All amounts in the tables (except sales and customers) are in
millions of dollars.
Electric
Operating Revenue
2008
2007
Change
Regulated
T&D Electric Revenue
$
353
$
337
$
16
Default
Supply Revenue
846
846
-
Other
Electric Revenue
22
22
-
Total
Electric Operating Revenue
$
1,221
$
1,205
$
16
The table above shows the amount of
Electric Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
includes revenue from the delivery of electricity, including the delivery of
Default Electricity Supply, to DPL’s customers within its service territory at
regulated rates. Regulated T&D Electric Revenue also includes
transmission service revenue that DPL receives as a transmission owner from PJM
Interconnection, LLC (PJM).
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.
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 include mutual
assistance to other utilities, highway relocation, rentals of pole attachments,
late payment fees, and collection fees.
Regulated T&D Electric
Regulated
T&D Electric Revenue
2008
2007
Change
Residential
$
161
$
166
$
(5)
Commercial
91
91
-
Industrial
12
12
-
Other
89
68
21
Total
Regulated T&D Electric Revenue
$
353
$
337
$
16
Other
Regulated T&D Electric Revenue consists primarily of (i) transmission
service revenue, and (ii) either (a) a positive adjustment equal to the amount
by which revenue from Maryland retail distribution sales falls short of the
revenue that DPL is entitled to earn based on the distribution charge per
customer approved in the 2007 Maryland Rate Order or (b) a
negative
118
DPL
adjustment
equal to the amount by which revenue from such distribution sales exceeds the
revenue that DPL is entitled to earn based on the approved distribution charge
per customer (a Revenue Decoupling Adjustment).
Regulated
T&D Electric Sales (Gigawatt hours (GWh))
2008
2007
Change
Residential
5,038
5,333
(295)
Commercial
5,275
5,471
(196)
Industrial
2,652
2,825
(173)
Other
50
51
(1)
Total
Regulated T&D Electric Sales
13,015
13,680
(665)
Regulated
T&D Electric Customers (in thousands)
2008
2007
Change
Residential
438
456
(18)
Commercial
58
61
(3)
Industrial
1
1
-
Other
1
1
-
Total
Regulated T&D Electric Customers
498
519
(21)
Due to
the sale of DPL’s Virginia retail electric distribution assets in
January 2008, the numbers of Regulated T&D Electric Customers listed
above include a decrease of approximately 19,000 residential customers and 3,000
commercial customers.
Regulated
T&D Electric Revenue increased by $16 million primarily due to:
·
An
increase of $15 million primarily due to transmission rate changes in June
2008 and 2007.
·
An
increase of $12 million due to a distribution rate change under the 2007
Maryland Rate Order that became effective in June 2007, including a
positive $6 million Revenue Decoupling
Adjustment.
·
An
increase of $7 million due to differences in consumption among the various
customer rate classes.
The
aggregate amount of these increases was partially offset
by:
·
A
decrease of $12 million due to the sale of Virginia retail electric
distribution and wholesale transmission assets in January
2008.
·
A
decrease of $6 million due to lower weather-related sales (a 2% increase
in Heating Degree Days and a 23% decrease in Cooling Degree
Days).
119
DPL
Default Electricity Supply
Default
Supply Revenue
2008
2007
Change
Residential
$
553
$
556
$
(3)
Commercial
249
239
10
Industrial
35
42
(7)
Other
9
9
-
Total
Default Supply Revenue
$
846
$
846
$
-
Default
Electricity Supply Sales (GWh)
2008
2007
Change
Residential
4,923
5,257
(334)
Commercial
2,263
2,291
(28)
Industrial
357
551
(194)
Other
43
45
(2)
Total
Default Electricity Supply Sales
7,586
8,144
(558)
Default
Electricity Supply Customers (in thousands)
2008
2007
Change
Residential
431
447
(16)
Commercial
49
51
(2)
Industrial
-
-
-
Other
1
1
-
Total
Default Electricity Supply Customers
481
499
(18)
Due to
the sale of DPL’s Virginia retail electric distribution assets in January 2008,
the numbers of Default Electricity Supply Customers listed above include a
decrease of approximately 19,000 residential customers and 3,000 commercial
customers.
Default
Supply Revenue, which is substantially offset in Fuel and Purchased Energy, did
not change primarily due to:
·
An
increase of $42 million in market-based Default Electricity Supply
rates.
·
An
increase of $8 million primarily due to existing commercial customers
electing to purchase a decreased amount of electricity from competitive
suppliers.
The
aggregate amount of these increases was offset by:
·
A
decrease of $32 million due to the sale of Virginia retail electric
distribution and wholesale transmission assets in January
2008.
·
A
decrease of $17 million due to lower weather-related sales (a 2% increase
in Heating Degree Days and a 23% decrease in Cooling Degree
Days).
The following table shows the
percentages of DPL’s total sales by jurisdiction that are derived from customers
receiving Default Electricity Supply distribution from DPL.
120
DPL
2008
2007
Sales
to Delaware customers
55%
54%
Sales
to Maryland customers
65%
67%
Sales
to Virginia customers
-%
94%
Natural
Gas Operating Revenue
2008
2007
Change
Regulated
Gas Revenue
$
204
$
211
$
(7)
Other
Gas Revenue
114
80
34
Total
Natural Gas Operating Revenue
$
318
$
291
$
27
The table above shows the amounts of
Natural Gas Operating Revenue from sources that are subject to price regulation
(Regulated Gas Revenue) and those that generally are not subject to price
regulation (Other Gas Revenue). Regulated Gas Revenue includes the
revenue DPL receives from on-system natural gas delivered sales and the
transportation of natural gas for customers within its service
territory. Other Gas Revenue includes off-system natural gas sales
and the sale of excess system capacity.
Regulated Gas Revenue
Regulated
Gas Revenue
2008
2007
Change
Residential
$
121
$
124
$
(3)
Commercial
69
73
(4)
Industrial
6
8
(2)
Transportation
and Other
8
6
2
Total
Regulated Gas Revenue
$
204
$
211
$
(7)
Regulated
Gas Sales (billion cubic feet)
2008
2007
Change
Residential
7
8
(1)
Commercial
5
5
-
Industrial
1
1
-
Transportation
and Other
7
7
-
Total
Regulated Gas Sales
20
21
(1)
Regulated
Gas Customers (in thousands)
2008
2007
Change
Residential
113
112
1
Commercial
9
10
(1)
Industrial
-
-
-
Transportation
and Other
-
-
-
Total
Regulated Gas Customers
122
122
-
121
DPL
Regulated
Gas Revenue decreased by $7 million primarily due to:
·
A
decrease of $4 million due to differences in consumption among the various
customer rate classes.
·
A
decrease of $3 million due to lower weather-related sales (a 3% decrease
in Heating Degree Days).
·
A
decrease of $2 million primarily due to Gas Cost Rate changes effective
April 2007, November 2007 and November
2008.
The
aggregate amount of these decreases was partially offset by:
·
An
increase of $2 million due to a distribution base rate change effective in
April 2007.
Other
Gas Revenue
Other Gas
Revenue, which is substantially offset in Gas Purchased expense, increased by
$34 million primarily due to revenue from higher off-system sales, the result of
an increase in market prices. Off-system sales are made possible due
to available pipeline capacity that results from low demand for natural gas from
regulated customers.
Operating
Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is
primarily associated with Default Electricity Supply revenue, decreased by $18
million to $821 million in 2008 from $839 million in 2007. The
decrease was primarily due to:
·
A
decrease of $45 million due to the sale of Virginia retail electric
distribution and wholesale transmission assets in January
2008.
·
A
decrease of $18 million due to lower weather-related
sales.
The aggregate amount of these decreases
was partially offset by:
·
An
increase of $33 million in average energy costs, the result of new Default
Electricity Supply contracts.
·
An
increase of $11 million due to a higher rate of recovery of electric
supply costs resulting in a change in the Default Electric Supply deferral
balance.
Fuel and
Purchased Energy expense is substantially offset in Default Supply
Revenue.
122
DPL
Gas
Purchased
Total Gas
Purchased, which is primarily offset in Regulated Gas Revenue and Other Gas
Revenue, increased by $25 million to $245 million in 2008 from $220 million in
2007. The increase is primarily due to:
·
An
increase of $32 million in gas purchases for off-system sales, the result
of higher average gas costs.
The
increase was partially offset by:
·
A
decrease of $10 million due to a lower rate of recovery of natural gas
supply costs resulting in a change in the deferred gas fuel
balance.
Other
Operation and Maintenance
Other
Operation and Maintenance increased by $16 million to $222 million in 2008 from
$206 million in 2007. The increase was primarily due to the
following:
·
An
increase of $10 million in deferred administrative expenses associated
with Default Electricity Supply (offset in Default Supply Revenue) due to
(i) the inclusion of $5 million of customer late payment fees in the
calculation of the deferral and (ii) a higher rate of recovery of bad debt
and administrative expenses as a result of an increase in Default
Electricity Supply revenue rates. See the discussion below
regarding the 2008 correction of an error in recording customer late
payment fees, including $3 million related to prior
periods.
·
An
increase of $5 million due to higher bad debt expenses associated with
distribution and Default Electricity Supply customers, of which
approximately $2 million was
deferred.
·
An
increase of $2 million in employee-related costs due to the recording of
additional stock-based compensation expense as discussed below, including
$2 million related to prior
periods.
The
aggregate amount of these increases was partially offset by:
·
A
decrease of $2 million primarily in emergency restoration
costs.
During
2008, DPL recorded adjustments to correct errors in Other Operation and
Maintenance expenses for prior periods dating back to May 2006 during which (i)
customer late payment fees were incorrectly recognized and (ii) stock-based
compensation expense related to certain restricted stock awards granted under
the Long-Term Incentive Plan was understated. These adjustments resulted in a
total increase in Other Operation and Maintenance expenses for the year ended
December 31, 2008 of $5 million.
123
DPL
Gain
on Sale of Assets
Gain on
Sale of Assets increased by $3 million to $4 million in 2008 from $1 million in
2007. The increase was primarily due to a $4 million gain on the sale
of Virginia retail electric distribution and wholesale transmission assets in
January 2008.
Other
Income (Expenses)
Other Expenses (which are net of Other
Income) decreased by $5 million to a net expense of $35 million in 2008 from a
net expense of $40 million in 2007. The decrease was primarily due to
a $4 million net decrease in interest expense on short and long-term
debt.
Income
Tax Expense
DPL’s effective tax rates for the years
ended December 31, 2008 and 2007 were 39.8% and 45.1%,
respectively. While the change in the effective rate between 2008 and
2007 was not significant, the effective rate in each year was impacted by
certain non-recurring items. In 2008, DPL recorded certain tax
benefits that reduced its overall effective tax rate, primarily representing net
interest income accrued on the tentative settlement with the Internal Revenue
Service (IRS) on the mixed service cost issue discussed below. This
benefit was largely offset by income tax charges recorded in the fourth quarter
of 2008 related to additional analysis of DPL’s deferred tax
balances. In 2007, DPL recorded certain income tax charges in the
third quarter of 2007 related to additional analysis of DPL’s deferred tax
balances.
During the second quarter 2008, DPL
reached a tentative settlement with the Internal Revenue Service concerning the
treatment of mixed service costs for income tax purposes during the period 2001
to 2004. On the basis of the tentative settlement, DPL updated its
estimated liability related to mixed service costs and, as a result, recorded a
net reduction in its liability for unrecognized tax benefits of $1 million and
recognized after-tax interest income of $2 million in the second quarter of
2008. See Note (14), “Commitments and Contingencies — Regulatory and
Other Matters — IRS Mixed Service Cost Issue,” to the financial statements of
DPL set forth in Item 8 of this Form 10-K.
Capital
Requirements
Capital
Expenditures
DPL’s total capital expenditures for
the year ended December 31, 2008, totaled $150 million. These
expenditures were primarily related to capital costs associated with new
customer services, distribution reliability and transmission.
124
DPL
The table below shows DPL’s projected
capital expenditures for the five-year period 2009 through 2013:
For
the Year
2009
2010
2011
2012
2013
Total
(Millions
of Dollars)
DPL
Distribution
$
104
$
98
$
108
$
120
$
119
$
549
Distribution
- Blueprint for the Future
31
47
1
40
-
119
Transmission
65
46
60
72
122
365
Transmission
- Mid-Atlantic Power Pathway (MAPP)
10
94
181
345
220
850
Gas
Delivery
20
21
20
21
19
101
Other
18
23
18
14
11
84
$
248
$
329
$
388
$
612
$
491
$
2,068
DPL expects to fund these expenditures
through internally generated cash and from external financing and capital
contributions from PHI.
As
further discussed in Note (11), “Debt,” to the DPL financial statements set
forth in Item 8 of this Form 10-K, PHI, Potomac Electric Power Company (Pepco),
DPL and Atlantic City Electric Company (ACE) maintain credit facilities to
provide for their respective short-term liquidity needs. The
aggregate borrowing limit under the facilities is $1.9 billion. The primary
facility consists of a $1.5 billion facility which expires in 2012, all or any
portion of which may be used to obtain loans or to issue letters of credit.
PHI’s credit limit under the facility is $875 million. The credit limit for DPL
is the lesser of $500 million and the maximum amount of debt the company is
permitted to have outstanding by its regulatory authorities which is $500
million, except that the aggregate amount of credit used by Pepco, DPL and ACE
at any given time collectively may not exceed $625 million.
Distribution, Transmission and Gas
Delivery
The projected capital expenditures
listed in the table 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.
Blueprint for the Future
During 2007, DPL announced an
initiative that is referred to as the “Blueprint for the Future.” This
initiative combines traditional energy efficiency programs with new technologies
and systems to help customers manage their energy use and reduce the total cost
of energy, and includes the installation of “smart meters” for all customers in
Delaware and Maryland. DPL has made filings with the Delaware Public
Service Commission (DPSC) and the MPSC for approval of certain aspects of these
programs. Delaware has approved a recovery mechanism associated with these
plans, and work has proceeded to prepare to begin installation of an Advanced
Metering Infrastructure (AMI) by the last quarter of 2009. On
December 31, 2008, the MPSC conditionally approved four residential and four
non-residential DSM/energy efficiency programs. The MPSC will
consider an AMI program in a separate proceeding. DPL anticipates that the costs
of these programs will be recovered through a previously approved surcharge
mechanism.
125
DPL
MAPP Project
In October 2007, the PJM Board of
Managers approved PHI’s proposed MAPP transmission project for construction of a
new 230-mile, 500-kilovolt interstate transmission project at a then-estimated
cost of $1 billion. This MAPP project will originate at Possum Point
substation in northern Virginia, connect into three substations across southern
Maryland, cross the Chesapeake Bay, tie into two substations across the Delmarva
Peninsula and terminate at Salem substation in southern New
Jersey. This MAPP project is part of PJM’s Regional
Transmission Expansion Plan required to address the reliability objectives of
the PJM RTO system. On December 4, 2008, the PJM Board approved a
direct-current technology for segments of the project including the Chesapeake
Bay Crossing. With this modification, the cost of the MAPP project is
currently estimated at $1.4 billion. PJM has determined that the line
segment from Possum Point substation to the second substation on the Delmarva
Peninsula (Indian River substation) is required to be operational by June 1,2013. PJM is continuing to evaluate the in-service date for the
remaining 80-miles of line segment to connect the Indian River substation to the
Salem substation. Construction is expected to occur in sections over the
next five year period.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding
DPL’s intents, beliefs and current expectations. In some cases, you
can identify forward-looking statements by terminology such as “may,”“will,”“should,”“expects,”“plans,”“anticipates,”“believes,”“estimates,”“predicts,”“potential” or “continue” or the negative of such terms or other
comparable terminology. Any forward-looking statements are not
guarantees of future performance, and actual results could differ materially
from those indicated by the forward-looking
statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause DPL’s actual results, levels of activity, performance or achievements to
be materially different from any future results, levels of activity, performance
or achievements expressed or implied by such forward-looking
statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond DPL’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
·
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
·
Changes
in and compliance with environmental and safety laws and
policies;
·
Weather
conditions;
·
Population
growth rates and demographic
patterns;
126
DPL
·
Competition
for retail and wholesale customers;
·
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
·
Growth
in demand, sales and capacity to fulfill
demand;
·
Changes
in tax rates or policies or in rates of inflation;
·
Changes
in accounting standards or
practices;
·
Changes
in project costs;
·
Unanticipated
changes in operating expenses and capital
expenditures;
·
The
ability to obtain funding in the capital markets on favorable
terms;
·
Rules
and regulations imposed by federal and/or state regulatory commissions,
PJM, the North American Electric Reliability Council and other applicable
electric reliability organizations
·
Legal
and administrative proceedings (whether civil or criminal) and settlements
that influence DPL’s business and
profitability;
·
Volatility
in market demand and prices for energy, capacity and
fuel;
·
Interest
rate fluctuations and credit and capital market conditions;
and
·
Effects
of geopolitical events, including the threat of domestic
terrorism.
Any forward-looking statements speak
only as to the date of this Annual Report and DPL undertakes no obligation to
update any forward looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it is
not possible for DPL to predict all of such factors, nor can DPL assess the
impact of any such factor on DPL’s business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
127
THIS
PAGE LEFT INTENTIONALLY BLANK.
128
ACE
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
ATLANTIC
CITY ELECTRIC COMPANY
GENERAL
OVERVIEW
Atlantic City Electric Company (ACE) is
engaged in the transmission and distribution of electricity in southern New
Jersey. ACE provides Default Electricity Supply, which is the supply
of electricity at regulated rates to retail customers in its service territory
who do not elect to purchase electricity from a competitive
supplier. Default Electricity Supply is also known as Basic
Generation Service (BGS) in New Jersey. ACE’s service territory
covers approximately 2,700 square miles and has a population of approximately
1.1 million.
ACE is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco
Holdings). Because PHI is a public utility holding company subject to
the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship
between PHI and ACE and certain activities of ACE are subject to the regulatory
oversight of Federal Energy Regulatory Commission under PUHCA 2005.
DISCONTINUED
OPERATIONS
In February 2007, ACE completed the
sale of the B.L. England generating facility. B.L. England comprised
a significant component of ACE’s generation operations and its sale required
discontinued operations presentation under Statement of Financial Accounting
Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived
Assets,” on ACE’s Consolidated Statements of Earnings for the years ended
December 31, 2007 and 2006. In September 2006, ACE sold its interests
in the Keystone and Conemaugh generating facilities, which for the year ended
December 31, 2006, is also reflected as discontinued operations.
The following table summarizes
information related to the discontinued operations for the years presented
(millions of dollars):
2008
2007
2006
Operating
Revenue
$
-
$
10
$
114
Income
Before Income Tax Expense
$
-
$
-
$
4
Net
Income
$
-
$
-
$
2
IMPACT
OF THE CURRENT CAPITAL AND CREDIT MARKET DISRUPTIONS
The
recent disruptions in the capital and credit markets have had an impact on ACE’s
business. While these conditions have required ACE to make certain
adjustments in its financial management activities, ACE believes that it
currently has sufficient liquidity to fund its operations and meet its financial
obligations. These market conditions, should they continue, however,
could have a negative effect on ACE’s financial condition, results of operations
and cash flows.
129
ACE
Liquidity
Requirements
ACE depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, ACE historically has relied on the issuance of
commercial paper and short-term notes and on bank lines of credit to supplement
internally generated cash from operations. ACE’s primary credit
source is PHI’s $1.5 billion syndicated credit facility, under which ACE can
borrow funds, obtain letters of credit and support the issuance of commercial
paper in an amount up to $500 million (subject to the limitation that the total
utilization by ACE and PHI’s other utility subsidiaries cannot exceed $625
million). This facility is in effect until May 2012 and consists of
commitments from 17 lenders, no one of which is responsible for more than 8.5%
of the total commitment.
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, ACE has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. After giving effect to
outstanding letters of credit and commercial paper, PHI’s utility subsidiaries
have an aggregate of $843 million in combined cash and borrowing capacity under
the credit facility at December 31, 2008. During the months of
January and February 2009, the average daily amount of the combined cash and
borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged
from a low of $673 million to a high of $1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, ACE has
identified a number of cash and liquidity conservation measures, including
opportunities to defer capital expenditures due to lower than anticipated
growth. Several measures to reduce expenditures have been
taken. Additional measures could be undertaken if conditions
warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, ACE issued $250 million in
long-term debt securities in November. The proceeds were used to
refund short-term debt incurred to finance utility construction and operations
on a temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
ACE participates in pension and
postretirement benefit plans sponsored by PHI for employees. While
the plans have not experienced any significant impact in terms of liquidity or
counterparty exposure due to the disruption of the capital and credit markets,
the recent stock market declines have caused a decrease in the market value of
benefit plan assets in 2008. ACE expects to contribute approximately $60 million
to the pension plan in 2009.
130
ACE
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2008 to the year ended
December 31, 2007. Other than this disclosure, information under this
item has been omitted in accordance with General Instruction I(2)(a) to the Form
10-K. All amounts in the tables (except sales and customers) are in
millions of dollars.
Operating
Revenue
2008
2007
Change
Regulated
T&D Electric Revenue
$
359
$
327
$
32
Default
Supply Revenue
1,258
1,199
59
Other
Electric Revenue
16
17
(1)
Total
Operating Revenue
$
1,633
$
1,543
$
90
The table above shows the amount of
Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
includes revenue from the delivery of electricity, including the delivery of
Default Electricity Supply, to ACE’s customers within its service territory at
regulated rates. Regulated T&D Electric Revenue also includes
transmission service revenue that ACE receives as a transmission owner from PJM
Interconnection, LLC (PJM).
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. 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.
In response to an order issued by the
New Jersey Board of Public Utilities regarding changes to ACE’s retail
transmission rates, ACE has established deferred accounting treatment for the
difference between the rates that ACE is authorized to charge its customers for
the transmission of Default Electricity Supply and the cost that ACE incurs
based on transmission formula rates approved by the Federal Energy Regulatory
Commission (FERC). Under the deferral arrangement, any over or under
recovery is deferred as part of Deferred Electric Service Costs pending an
adjustment of retail rates in a future proceeding. As a consequence
of the order, effective January 1, 2008, ACE’s retail transmission revenue
is being recorded as Default Supply Revenue, rather than as Regulated T&D
Electric Revenue, thereby conforming to the practice of PHI’s other utility
subsidiaries, which previously established deferred accounting treatment for any
over or under recovery of retail transmission rates relative to the cost
incurred based on FERC-approved transmission formula rates. ACE’s
retail transmission revenue for the period prior to January 1, 2008 has
been reclassified to Default Supply Revenue in order to conform to the current
period presentation.
131
ACE
Regulated T&D Electric
Regulated
T&D Electric Revenue
2008
2007
Change
Residential
$
160
$
150
$
10
Commercial
111
100
11
Industrial
17
14
3
Other
71
63
8
Total
Regulated T&D Electric Revenue
$
359
$
327
$
32
Other Regulated T&D Electric
Revenue consists primarily of transmission service revenue.
Regulated
T&D Electric Sales (Gigawatt hours (GWh))
2008
2007
Change
Residential
4,418
4,520
(102)
Commercial
4,492
4,469
23
Industrial
1,129
1,149
(20)
Other
50
49
1
Total
Regulated T&D Electric Sales
10,089
10,187
(98)
Regulated
T&D Electric Customers (in thousands)
2008
2007
Change
Residential
481
479
2
Commercial
64
63
1
Industrial
1
1
-
Other
1
1
-
Total
Regulated T&D Electric Customers
547
544
3
Regulated
T&D Electric Revenue increased by $32 million primarily due to:
·
An
increase of $24 million due to a distribution rate change as part of a
higher New Jersey Societal Benefit Charge that became effective in June
2008 (substantially offset in Deferred Electric Service
Costs).
·
An
increase of $8 million primarily due to transmission rate changes in June
2008 and 2007.
132
ACE
Default Electricity Supply
Default
Supply Revenue
2008
2007
Change
Residential
$
525
$
513
$
12
Commercial
378
375
3
Industrial
40
52
(12)
Other
315
259
56
Total
Default Supply Revenue
$
1,258
$
1,199
$
59
Other Default Supply Revenue consists
primarily of revenue from the resale in the PJM RTO market of energy and
capacity purchased under contracts with non-utility generators
(NUGs).
Default
Electricity Supply Sales (GWh)
2008
2007
Change
Residential
4,388
4,520
(132)
Commercial
3,175
3,235
(60)
Industrial
283
363
(80)
Other
49
49
-
Total
Default Electricity Supply Sales
7,895
8,167
(272)
Default
Electricity Supply Customers (in thousands)
2008
2007
Change
Residential
481
479
2
Commercial
64
63
1
Industrial
1
1
-
Other
1
1
-
Total
Default Electricity Supply Customers
547
544
3
Default Supply Revenue, which is
substantially offset in Fuel and Purchased Energy and Deferred Electric Service
Costs, increased by $59 million primarily due to:
·
An
increase of $57 million in wholesale energy revenues due to the sale at
higher market prices of electricity purchased from
NUGs.
·
An
increase of $34 million in market-based Default Electricity Supply
rates.
The aggregate amount of these increases was partially offset by:
·
A
decrease of $19 million primarily due to existing commercial and
industrial customers electing to purchase electricity from competitive
suppliers.
·
A
decrease of $10 million due to lower weather-related sales (a 2% decrease
in Heating Degree Days and a 3% decrease in Cooling Degree
Days).
133
ACE
For the years ended December 31, 2008
and 2007, the percentage of ACE’s total distribution sales that are derived from
customers receiving Default Electricity Supply are 78% and 80%,
respectively.
Operating
Expenses
Fuel and Purchased Energy
Fuel and
Purchased Energy, which is primarily associated with Default Electricity Supply
sales, increased by $127 million to $1,178 million in 2008 from $1,051 million
in 2007. The increase was primarily due to:
·
An
increase of $162 million in average energy costs, the result of new
Default Electricity Supply
contracts.
The
increase was partially offset by:
·
A
decrease of $21 million primarily due to commercial and industrial
customers electing to purchase electricity from competitive
suppliers.
·
A
decrease of $14 million due to lower weather-related
sales.
Fuel and
Purchased Energy is substantially offset in Default Supply Revenue and Deferred
Electric Service Costs.
Other
Operation and Maintenance
Other
Operation and Maintenance increased by $18 million to $183 million in 2008 from
$165 million in 2007. The increase was primarily due to the
following:
·
An
increase of $4 million in preventative maintenance and system operation
costs.
·
An
increase of $3 million due to higher bad debt expenses associated with
distribution customers (offset in Deferred Electric Service
Costs).
·
An
increase of $3 million in Demand Side Management program costs (offset in
Deferred Electric Service Costs).
·
An
increase of $2 million in employee-related costs, primarily due to the
recording of additional stock-based compensation expense as discussed
below, including $1 million related to prior
periods.
·
An
increase of $2 million in costs associated with Default Electricity
Supply.
·
An
increase of $1 million in legal
expenses.
During
2008, ACE recorded an adjustment to correct errors in Other Operation and
Maintenance expenses for certain restricted stock awards granted under the
Long-Term Incentive Plan. This adjustment resulted in an increase in Other
Operation and Maintenance expenses for the year ended December 31, 2008 of $1
million.
134
ACE
Depreciation and
Amortization
Depreciation
and Amortization expenses increased by $24 million to $104 million in 2008 from
$80 million in 2007. This increase was primarily due to higher
amortization of stranded costs as a result of an October 2007 Transition Bond
Charge rate increase (offset in Default Supply Revenue).
Deferred
Electric Service Costs
Deferred
Electric Service Costs decreased by $75 million to income of $9 million in 2008
from an expense of $66 million in 2007. The decrease was primarily
due to:
·
A
decrease of $46 million due to a lower rate of recovery associated with
deferred energy costs.
·
A
decrease of $29 million due to a lower rate of recovery of costs
associated with energy and capacity purchased under the
NUGs.
·
A
decrease of $17 million due to a lower rate of recovery associated with
deferred transmission costs.
The aggregate amount of these decreases was partially offset by:
·
An
increase of $15 million primarily due to a higher rate of recovery
associated with Demand Side Management program
costs.
Deferred
Electric Service Costs are substantially offset in Regulated T&D Electric
Revenue and Other Operation and Maintenance.
Income
Tax Expense
ACE’s effective tax rates for the years
ended December 31, 2008 and 2007 were 31.9% and 40.6%,
respectively. The significant year-over-year decline in the effective
tax rate reflects certain non-recurring items recorded in 2008. In
2008, ACE recorded certain tax benefits that reduced its overall effective tax
rate, primarily representing net interest income accrued on uncertain tax
positions (including interest related to the tentative settlement with the IRS
on the mixed service cost issue discussed below and a claim made with the IRS
related to the tax reporting of fuel over- and
under-recoveries). This benefit was partially offset by income tax
charges recorded in the fourth quarter of 2008 related to additional analysis of
ACE’s deferred tax balances completed in 2008. In 2007, ACE recorded
certain income tax credits in the third quarter of 2007 related to additional
analysis of ACE’s deferred tax balances.
During the second quarter 2008, ACE
reached a tentative settlement with the Internal Revenue Service concerning the
treatment of mixed service costs for income tax purposes during the period 2001
to 2004. On the basis of the tentative settlement, ACE updated its
estimated liability related to mixed service costs and, as a result, recorded a
net reduction in its liability for unrecognized tax benefits of $2 million and
recognized after-tax interest income of $2 million in the second quarter of
2008. See Note (14), “Commitments and Contingencies — Regulatory and
Other Matters — IRS Mixed Service Cost Issue,” to the consolidated financial
statements of ACE set forth in Item 8 of this Form 10-K.
135
ACE
Capital
Requirements
Capital
Expenditures
ACE’s total capital expenditures for
the year ended December 31, 2008, totaled $162 million. These
expenditures were primarily related to capital costs associated with new
customer services, distribution reliability and transmission.
The table below shows ACE’s projected
capital expenditures for the five-year period 2009 through 2013:
For
the Year
2009
2010
2011
2012
2013
Total
(Millions
of Dollars)
ACE
Distribution
$
97
$
96
$
104
$
109
$
111
$
517
Distribution
- Blueprint for the Future
5
8
1
-
8
22
Transmission
26
25
32
34
33
150
Transmission
- Mid-Atlantic Power Pathway (MAPP)
-
-
-
1
20
21
Other
11
14
18
17
12
72
$
139
$
143
$
155
$
161
$
184
$
782
ACE expects to fund these expenditures
through internally generated cash and from external financing and capital
contributions from PHI.
As
further discussed in Note (10), “Debt,” to the ACE consolidated financial
statements set forth in Item 8 of this Form 10-K, PHI, Potomac Electric Power
Company (Pepco), Delmarva Power & Light Company (DPL) and ACE maintain
credit facilities to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under the facilities is $1.9
billion. The primary facility consists of a $1.5 billion facility
which expires in 2012, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit for ACE is the lesser of $500 million and the
maximum amount of debt the company is permitted to have outstanding by its
regulatory authorities which is $250 million, except that the aggregate amount
of credit used by Pepco, DPL and ACE at any given time collectively may not
exceed $625 million.
Distribution and
Transmission
The projected capital expenditures
listed in the table for distribution (other than Blueprint for the Future) and
transmission (other than MAPP) are primarily for facility replacements and
upgrades to accommodate customer growth and reliability.
Blueprint for the Future
During 2007, ACE announced an
initiative that is referred to as the “Blueprint for the Future.” This
initiative combines traditional energy efficiency programs with new technologies
and systems to help customers manage their energy use and reduce the total cost
of energy, and includes the installation of “smart meters” for all customers in
New Jersey. In November 2007, ACE filed its “Blueprint for the
Future” proposal with the New Jersey Board of Public Utilities.
136
ACE
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding ACE’s
intents, beliefs and current expectations. In some cases, you can identify
forward-looking statements by terminology such as “may,”“will,”“should,”“expects,”“plans,”“anticipates,”“believes,”“estimates,”“predicts,”“potential” or “continue” or the negative of such terms or other comparable
terminology. Any forward-looking statements are not guarantees of future
performance, and actual results could differ materially from those indicated by
the forward-looking statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause ACE’s actual results, levels of activity, performance or achievements to
be materially different from any future results, levels of activity, performance
or achievements expressed or implied by such forward-looking
statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond ACE’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
·
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
·
Changes
in and compliance with environmental and safety laws and
policies;
·
Weather
conditions;
·
Population
growth rates and demographic
patterns;
·
Competition
for retail and wholesale customers;
·
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
·
Growth
in demand, sales and capacity to fulfill
demand;
·
Changes
in tax rates or policies or in rates of inflation;
·
Changes
in accounting standards or
practices;
·
Changes
in project costs;
·
Unanticipated
changes in operating expenses and capital
expenditures;
·
The
ability to obtain funding in the capital markets on favorable
terms;
137
ACE
·
Rules
and regulations imposed by federal and/or state regulatory commissions,
PJM, the North American Electric Reliability Council and other applicable
electric reliability organizations;
·
Legal
and administrative proceedings (whether civil or criminal) and settlements
that influence ACE’s business and
profitability;
·
Volatility
in market demand and prices for energy, capacity and
fuel;
·
Interest
rate fluctuations and credit and capital market conditions;
and
·
Effects
of geopolitical events, including the threat of domestic
terrorism.
Any forward-looking statements speak
only as to the date of this Annual Report and ACE undertakes no obligation to
update any forward looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it is
not possible for ACE to predict all of such factors, nor can ACE assess the
impact of any such factor on ACE’s business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
138
THIS
PAGE LEFT INTENTIONALLY BLANK.
139
Item
7A.
QUANTITATIVE AND
QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
Risk management policies for PHI and
its subsidiaries are determined by PHI’s Corporate Risk Management Committee,
the members of which are PHI’s Chief Risk Officer, Chief Operating Officer,
Chief Financial Officer, General Counsel, Chief Information Officer and other
senior executives. The Corporate Risk Management Committee monitors
interest rate fluctuation, commodity price fluctuation, and credit risk
exposure, and sets risk management policies that establish limits on unhedged
risk and determine risk reporting requirements. For information about PHI’s
derivative activities, other than the information disclosed herein, refer to
Note (2), “Significant Accounting Policies - Accounting For Derivatives” and
Note (17), “Use of Derivatives in Energy and Interest Rate Hedging Activities”
to the consolidated financial statements of PHI set forth in Item 8 of this Form
10-K.
Pepco Holdings,
Inc.
Commodity Price
Risk
The Competitive Energy segments
actively engage in commodity risk management activities to reduce their
financial exposure to changes in the value of their assets and obligations due
to commodity price fluctuations. Certain of these risk management
activities are conducted using instruments classified as derivatives under
Statement of Financial Accounting Standards (SFAS) No. 133. The
Competitive Energy segments also manage commodity risk with contracts that are
not classified as derivatives. The Competitive Energy segments’
primary risk management objectives are (1) to manage the spread between the cost
of fuel used to operate their electric generation plants and the revenue
received from the sale of the power produced by those plants by selling forward
a portion of their projected plant output and buying forward a portion of their
projected fuel supply requirements and (2) to manage the spread between
wholesale and retail sales commitments and the cost of supply used to service
those commitments in order to ensure stable and known cash flows and fix
favorable prices and margins when they become available.
PHI’s risk management policies place
oversight at the senior management level through the Corporate Risk Management
Committee which has the responsibility for establishing corporate compliance
requirements for the Competitive Energy businesses’ energy market
participation. PHI collectively refers to these energy market
activities, including its commodity risk management activities, as “energy
commodity” activities. PHI uses a value-at-risk (VaR) model to assess
the market risk of its Competitive Energy segments’ energy commodity
activities. PHI also uses other measures to limit and monitor risk in
its energy commodity activities, including limits on the nominal size of
positions and periodic loss limits. VaR represents the potential fair
value loss on energy contracts or portfolios due to changes in market prices for
a specified time period and confidence level. PHI estimates VaR using
a delta-normal variance / covariance model with a 95 percent, one-tailed
confidence level and assuming a one-day holding period. Since VaR is
an estimate, it is not necessarily indicative of actual results that may
occur.
This
column represents all energy derivative contracts, normal purchase and
sales contracts, modeled generation output and fuel requirements and
modeled customer load obligations for PHI’s energy commodity
activities.
Conectiv Energy economically hedges
both the estimated plant output and fuel requirements as the estimated levels of
output and fuel needs change. Economic hedge percentages include the
estimated electricity output of Conectiv Energy’s generation plants and any
associated financial or physical commodity contracts (including derivative
contracts that are classified as cash flow hedges under SFAS No. 133, other
derivative instruments, wholesale normal purchase and sales contracts, and
default electricity supply contracts).
Conectiv Energy maintains a forward 36
month program with targeted ranges for economically hedging its projected plant
output combined with its energy purchase commitments. Beginning in
2008, Conectiv Energy changed its disclosure to show the percentage of its
entire expected plant output and energy purchase commitments for all hours that
are hedged, as opposed to its hedged position with respect to its projected
on-peak plant output and on-peak energy commitments, which previously was
disclosed. This change was made in recognition of the significant
quantity of projected off-peak plant output and purchase commitments and due to
the increased volatility of power prices during off-peak hours. Also beginning
in 2008, Conectiv Energy is including default electricity supply contracts and
associated hedges in Independent System Operator - New
England. The hedge percentages for all expected plant output and
purchase commitment (based on the current forward electricity price curve) are
as follows:
The primary purpose of the risk
management program is to improve the predictability and stability of margins by
selling forward a portion of projected plant output, and buying forward
a
141
portion
of projected fuel supply requirements. Within each period, hedged
percentages can vary significantly above or below the average reported
percentages.
As of December 31, 2008, the
electricity sold forward by Conectiv Energy as a percentage of projected plant
output combined with energy purchase commitments was 81%, 75%, and 39% for the
1-12 month, 13-24 month and 25-36 month forward periods,
respectively. The amount of forward sales during the 1-12 month
period represents 21% of Conectiv Energy’s combined total generating capability
and energy purchase commitments. The volumetric percentages for the forward
periods can vary and may not represent the amount of expected value
hedged.
Not all of the value associated with
Conectiv Energy’s generation activities can be hedged such as the portion
attributable to ancillary services and fuel switching due to the lack of market
products, market liquidity, and other factors. Also the hedging of
locational value can be limited.
Pepco Energy Services purchases
electric and natural gas futures, swaps, options and forward contracts to hedge
price risk in connection with the purchase of physical natural gas and
electricity for delivery to customers. Pepco Energy Services accounts for its
futures and swap contracts as cash flow hedges of forecasted
transactions. Its options contracts and certain commodity contracts
that do not qualify as cash flow hedges are marked-to-market through current
earnings. Its forward contracts are accounted for using standard
accrual accounting since these contracts meet the requirements for normal
purchase and sale accounting under SFAS No. 133.
Credit and Nonperformance
Risk
Pepco Holdings’ subsidiaries attempt to
minimize credit risk exposure to wholesale energy counterparties through, among
other things, formal credit policies, regular assessment of counterparty
creditworthiness and the establishment of a credit limit for each counterparty,
monitoring procedures that include stress testing, the use of standard
agreements which allow for the netting of positive and negative exposures
associated with a single counterparty and collateral requirements under certain
circumstances, and have established reserves for credit losses. As of
December 31, 2008, credit exposure to wholesale energy counterparties was
weighted 78% with investment grade counterparties, 16% with counterparties
without external credit quality ratings, and 5% with non-investment grade
counterparties.
This table provides information on the
Competitive Energy businesses’ credit exposure, net of collateral, to wholesale
counterparties.
142
Schedule
of Credit Risk Exposure on Competitive Wholesale Energy
Contracts
Investment
Grade - primarily determined using publicly available credit ratings of
the counterparty. If the counterparty has provided a guarantee
by a higher-rated entity (e.g., its parent), it is determined based upon
the rating of its guarantor. Included in “Investment Grade” are
counterparties with a minimum Standard & Poor’s or Moody’s Investor
Service rating of BBB- or Baa3,
respectively.
(b)
Exposure
Before Credit Collateral - includes the marked to market (MTM) energy
contract net assets for open/unrealized transactions, the net
receivable/payable for realized transactions and net open positions for
contracts not subject to MTM. Amounts due from counterparties
are offset by liabilities payable to those counterparties to the extent
that legally enforceable netting arrangements are in
place. Thus, this column presents the net credit exposure to
counterparties after reflecting all allowable netting, but before
considering collateral held.
(c)
Credit
Collateral - the face amount of cash deposits, letters of credit and
performance bonds received from counterparties, not adjusted for
probability of default, and, if applicable, property interests (including
oil and gas reserves).
(d)
Using
a percentage of the total exposure.
Interest Rate
Risk
Pepco Holdings manages interest rates
through the use of fixed and, to a lesser extent, variable rate
debt. Pepco Holdings and its subsidiaries variable or floating rate
debt is subject to the risk of fluctuating interest rates in the normal course
of business. The effect of a hypothetical 10% change in interest
rates on the annual interest costs for short-term and variable rate debt was
approximately $2 million as of December 31, 2008.
Potomac Electric Power
Company
Interest Rate
Risk
Pepco’s debt is subject to the risk of fluctuating interest rates in the normal
course of business. Pepco manages interest rates through the use of fixed and,
to a lesser extent, variable rate debt. The effect of a hypothetical 10% change
in interest rates on the annual interest costs for short-term debt and variable
rate debt was approximately $1 million as of December 31, 2008.
Delmarva Power & Light
Company
Commodity Price
Risk
DPL uses derivative instruments
(forward contracts, futures, swaps, and exchange-traded and over-the-counter
options) primarily to reduce gas commodity price volatility while limiting its
customers’ exposure to increases in the market price of gas. DPL also
manages commodity
143
risk with
capacity contracts that do not meet the definition of
derivatives. The primary goal of these activities is to reduce the
exposure of its regulated retail gas customers to natural gas price
spikes. All premiums paid and other transaction costs incurred as
part of DPL’s natural gas hedging activity, in addition to all gains and losses
on the natural gas hedging activity, are fully recoverable through the gas cost
rate clause included in DPL’s gas tariff rates approved by the Delaware Public
Service Commission and are deferred under SFAS No. 71 until
recovered. At December 31, 2008, DPL had a net deferred derivative
payable of $56 million, offset by a $56 million regulatory asset. At
December 31, 2007, DPL had a net deferred derivative payable of $13
million, offset by a $13 million regulatory asset.
Interest Rate
Risk
DPL’s debt is subject to the risk of fluctuating interest rates in the normal
course of business. DPL manages interest rates through the use of fixed and, to
a lesser extent, variable rate debt. The effect of a hypothetical 10% change in
interest rates on the annual interest costs for short-term debt and variable
rate debt was approximately $1 million as of December 31, 2008.
Atlantic City Electric
Company
Interest Rate
Risk
ACE’s debt is subject to the risk of fluctuating interest rates in the normal
course of business. ACE manages interest rates through the use of fixed and, to
a lesser extent, variable rate debt. The effect of a hypothetical 10% change in
interest rates on the annual interest costs for short-term debt and variable
rate debt was less than $1 million as of December 31, 2008.
144
Item
8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA
Listed below is a table that sets
forth, for each registrant, the page number where the information is contained
herein.
Registrants
Item
Pepco
Holdings
Pepco
*
DPL
*
ACE
Management’s
Report on Internal Control
Over
Financial Reporting
146
237
281
322
Report
of Independent Registered
Public
Accounting Firm
147
238
282
323
Consolidated
Statements of Earnings
149
239
283
324
Consolidated
Statements
of
Comprehensive Earnings
150
240
N/A
N/A
Consolidated
Balance Sheets
151
241
284
325
Consolidated
Statements of Cash Flows
153
243
286
327
Consolidated
Statements
of
Shareholders’ Equity
154
244
287
328
Notes
to Consolidated
Financial
Statements
155
245
288
329
* Pepco
and DPL have no subsidiaries and therefore their financial statements are not
consolidated.
145
PEPCO
HOLDINGS
Management’s
Report on Internal Control over Financial Reporting
The management of Pepco Holdings is
responsible for establishing and maintaining adequate internal control over
financial reporting. Because of inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management assessed its internal
control over financial reporting as of December 31, 2008 based on the framework
in Internal Control —
Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on its assessment, the management
of Pepco Holdings concluded that its internal control over financial reporting
was effective as of December 31, 2008.
PricewaterhouseCoopers LLP, the
registered public accounting firm that audited the financial statements of Pepco
Holdings included in this Annual Report on Form 10-K, has issued its attestation
report on Pepco Holdings’ internal control over financial reporting, which is
included herein.
146
PEPCO
HOLDINGS
Report
of Independent Registered Public Accounting Firm
To the
Shareholders and Board of Directors of
Pepco
Holdings, Inc.
In our
opinion, the consolidated financial statements listed in the accompanying index
present fairly, in all material respects, the financial position of Pepco
Holdings, Inc. and its subsidiaries at December 31, 2008 and December 31, 2007,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2008 in conformity with
accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedules listed in the index appearing under Item 15(a)(2) present fairly, in
all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. Also
in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2008, based on
criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible
for these financial statements and financial statement schedules, for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting,
included in the accompanying Management’s Report on
Internal Control over Financial Reporting. Our responsibility is to express
opinions on these financial statements, on the financial statement schedules and
on the Company’s internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free
of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the
financial statements included examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
As
discussed in Note 12 to the consolidated financial statements, the Company
changed its manner of accounting and reporting for uncertain tax positions in
2007.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements
in
147
PEPCO
HOLDINGS
accordance
with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
The
accompanying Notes are an integral part of these Consolidated Financial
Statements
154
PEPCO
HOLDINGS
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
PEPCO
HOLDINGS, INC.
(1) ORGANIZATION
Pepco Holdings, Inc. (PHI or Pepco
Holdings), a Delaware corporation incorporated in 2001, is a diversified energy
company that, through its operating subsidiaries, is engaged primarily in two
businesses:
·
the
distribution, transmission and default supply of electricity and the
delivery and supply of natural gas (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:
o
Potomac
Electric Power Company (Pepco), which was incorporated in Washington, D.C.
in 1896 and became a domestic Virginia corporation in
1949,
o
Delmarva
Power & Light Company (DPL), which was incorporated in Delaware in
1909 and became a domestic Virginia corporation in 1979,
and
o
Atlantic
City Electric Company (ACE), which was incorporated in New Jersey in
1924.
·
competitive
energy generation, marketing and supply (Competitive Energy) conducted
through subsidiaries of Conectiv Energy Holding Company (collectively
Conectiv Energy) and Pepco Energy Services, Inc. and its subsidiaries
(collectively Pepco Energy
Services).
PHI Service Company, a subsidiary
service company of PHI, provides a variety of support services, including legal,
accounting, treasury, tax, purchasing and information technology services to PHI
and its operating subsidiaries. These services are provided pursuant
to a service agreement among PHI, PHI Service Company, and the participating
operating subsidiaries. The expenses of PHI Service Company are
charged to PHI and the participating operating subsidiaries in accordance with
costing methodologies set forth in the service agreement.
The following is a description of each
of PHI’s two principal business operations.
Power
Delivery
The largest component of PHI’s business
is Power Delivery. 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
155
PEPCO
HOLDINGS
service
territory. Together the three companies constitute a single segment
for financial reporting purposes.
Each company is responsible for the
delivery of electricity and, in the case of DPL, natural gas, in its service
territory, for which it is paid tariff rates established by the applicable local
public service commissions. Each company also supplies electricity at
regulated rates to retail customers in its service territory who do not elect to
purchase electricity from a competitive energy supplier. The
regulatory term for this supply service varies by jurisdiction as
follows:
Delaware
Standard
Offer Service (SOS)
District
of Columbia
SOS
Maryland
SOS
New
Jersey
Basic
Generation Service (BGS)
Effective
January 2, 2008, DPL sold its retail electric distribution assets and its
wholesale electric transmission assets in Virginia. Prior to that
date, DPL supplied electricity at regulated rates to retail customers in its
service territory who did not elect to purchase electricity from a competitive
energy supplier.
In this Form 10-K, these supply
services are referred to generally as Default Electricity Supply.
Competitive
Energy
The Competitive Energy business
provides competitive generation, marketing and supply of electricity and gas,
and related energy management services, primarily in the mid-Atlantic
region. PHI’s Competitive Energy operations are conducted through
Conectiv Energy and Pepco Energy Services, each of which is treated as a
separate operating segment for financial reporting purposes.
Over the past several months, PHI has
been conducting a strategic analysis of the retail energy supply business of
Pepco Energy Services. This review has included, among other things,
the evaluation of potential alternative supply arrangements to reduce collateral
requirements or a possible restructuring sale or wind down of the
business. Among the factors being considered is the return PHI earns
by investing capital in the retail energy supply business as compared to
alternative investments. PHI expects the retail energy supply
business to remain profitable based on its existing contract backlog and the
margins that have been locked in with corresponding wholesale energy purchase
contracts. The increased cost of capital associated with its
collateral obligations has been factored into its retail pricing and, as a
consequence, PES is experiencing reduced retail customer retention levels and
reduced levels of new retail customer acquisitions.
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, 2008 of
approximately $1.3 billion. This activity constitutes a fourth
operating segment for
156
PEPCO
HOLDINGS
financial
reporting purposes, which is designated as “Other Non-Regulated.” For
a discussion of PHI’s cross-border energy lease investments, see Note
(2), “Significant Accounting Policies - Changes in Accounting Estimates,” Note
(8), “Leasing Activities - Investment in Finance Leases Held in Trust,” Note
(12), “Income Taxes,” and Note (16), “Commitments and Contingencies - PHI’s
Cross-Border Energy Lease Investments.”
Impact of the Current
Capital and Credit Market Disruptions
The
recent disruptions in the capital and credit markets, combined with the
volatility of energy prices, have had an impact on several aspects of PHI’s
businesses. While these conditions have required PHI and its
subsidiaries to make certain adjustments in their financial management
activities, PHI believes that it and its subsidiaries currently have sufficient
liquidity to fund their operations and meet their financial
obligations. These market conditions, should they continue, could
have a negative effect on PHI’s financial condition, results of operations and
cash flows.
Liquidity
Requirements
PHI and its subsidiaries depend on
access to the capital and credit markets to meet their liquidity and capital
requirements. To meet their liquidity requirements, PHI’s utility
subsidiaries and its Competitive Energy businesses historically have relied on
the issuance of commercial paper and short-term notes and on bank lines of
credit to supplement internally generated cash from operations. PHI’s
primary credit source is its $1.5 billion syndicated credit facility, which can
be used by PHI and its utility subsidiaries to borrow funds, obtain letters of
credit and support the issuance of commercial paper. This facility is
in effect until May 2012 and consists of commitments from 17 lenders, no one of
which is responsible for more than 8.5% of the total $1.5 billion
commitment. The terms and conditions of the facility are more fully
described below in Note (11), “Debt.”
Due to the capital and credit market
disruptions, the market for commercial paper in the latter part of 2008 was
severely restricted for most companies. As a result, PHI and its
subsidiaries have not been able to issue commercial paper on a day-to-day basis
either in amounts or with maturities that they have typically required for cash
management purposes. To address the challenges posed by the current
capital and credit market environment and to ensure that PHI and its
subsidiaries will continue to have sufficient access to cash to meet their
liquidity needs, PHI and its subsidiaries have undertaken a number of actions,
including the following:
·
PHI
has conducted a review to identify cash and liquidity conservation
measures, including opportunities to reduce collateral obligations and to
defer capital expenditures due to lower than anticipated
growth. Several measures to reduce collateral obligations and
expenditures have been taken. Additional measures could be
undertaken if conditions warrant.
·
PHI
issued an additional 16.1 million shares of the Company’s common stock at
a price per share of $16.50 in November 2008, for net proceeds of $255
million.
·
PHI
added a 364-day $400 million credit facility in November
2008.
157
PEPCO
HOLDINGS
·
In
November 2008, ACE issued $250 million of First Mortgage Bonds, 7.75%
Series due November 15, 2018.
·
In
November 2008, DPL issued $250 million of First Mortgage Bonds, 6.40%
Series due December 1, 2013.
·
In
December 2008, Pepco issued $250 million of First Mortgage Bonds, 7.90%
Series due December 15, 2038.
At
December 31, 2008, the amount of cash, plus borrowing capacity under the
syndicated credit facility and PHI’s new 364-day credit facility, available to
meet the liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of
which $843 million consisted of the combined cash and borrowing capacity of
PHI’s utility subsidiaries. During the months of January and February
2009, the average daily amount of the combined cash and borrowing capacity of
PHI on a consolidated basis was $1.4 billion, and of its utility subsidiaries
was $831 million. This decrease in liquidity of PHI on a consolidated
basis was primarily due to increased collateral requirements of the Competitive
Energy businesses. During the months of January and February 2009,
the combined cash and borrowing capacity of PHI’s utility subsidiaries ranged
from a low of $673 million to a high of $1 billion.
Collateral
Requirements of the Competitive Energy Businesses
In conducting its retail energy sales
business, Pepco Energy Services typically enters into electricity and natural
gas sales contracts under which it is committed to supply the electricity or
natural gas requirements of its retail customers over a specified period at
agreed upon prices. Generally, Pepco Energy Services acquires the
energy to serve this load by entering into wholesale purchase
contracts. To protect the respective parties against the risk of
nonperformance by the other party, these wholesale purchase contracts typically
impose collateral requirements that are tied to changes in the price of the
contract commodity. In periods of energy market price volatility,
these collateral obligations can fluctuate materially on a day-to-day
basis.
Pepco Energy Services’ practice of
offsetting its retail energy sale obligations with corresponding wholesale
purchases of energy has the effect of substantially reducing the exposure of its
margins to energy price fluctuations. In addition, the
non-performance risks associated with its retail energy sales are relatively low
due to the inclusion of governmental entities among its customers and the
purchase of insurance on a significant portion of its commercial and other
accounts receivable. However, because its retail energy sales
contracts typically do not have collateral obligations, during periods of
declining energy prices Pepco Energy Services is exposed to the asymmetrical
risk of having to post collateral under its wholesale purchase contracts without
receiving a corresponding amount of collateral from its retail
customers. In the second half of 2008, the decrease in energy prices
has caused a significant increase in the collateral obligations of Pepco Energy
Services.
In addition, Conectiv Energy and Pepco
Energy Services in the ordinary course of business enter into various contracts
to buy and sell electricity, fuels and related products, including derivative
instruments, designed to reduce their financial exposure to changes in
the
158
PEPCO
HOLDINGS
value of
their assets and obligations due to energy price fluctuations. These
contracts also typically have collateral requirements.
Depending on the contract terms, the
collateral required to be posted by Pepco Energy Services and Conectiv Energy
can be of varying forms, including cash and letters of credit. As of
December 31, 2008, the Competitive Energy businesses had posted net cash
collateral of $331 million and letters of credit of $558 million.
At
December 31, 2008, the amount of cash, plus borrowing capacity under the
syndicated credit facility and PHI’s new 364-day credit facility, available to
meet the liquidity needs of the Competitive Energy businesses on a consolidated
basis totaled $684 million. During the months of January and February
2009, the combined cash and borrowing capacity available to PHI’s Competitive
Energy businesses ranged from a low of $378 million to a high of $757
million.
Counterparty
Credit Risk
PHI is exposed to the risk that the
counterparties to contracts may fail to meet their contractual payment
obligations or may fail to deliver purchased commodities or services at the
contracted price. PHI attempts to minimize these risks through, among other
things, formal credit policies, regular assessments of counterparty
creditworthiness, and the establishment of a credit limit for each
counterparty.
Pension
and Postretirement Benefit Plans
PHI and
its subsidiaries sponsor pension and postretirement benefit plans for their
employees. While the plans have not experienced any significant
impact in terms of liquidity or counterparty exposure due to the disruption of
the capital and credit markets, the stock market declines have caused a decrease
in the market value of benefit plan assets over the twelve months ended December31, 2008. The negative return did not have an impact on PHI’s results
of operations for 2008; however, this reduction in benefit plan assets will
result in increased pension and postretirement benefit costs in future
years.
PHI
expects to make a discretionary tax deductible contribution to the pension plan
in 2009 of approximately $300 million. The utility subsidiaries will
be responsible for funding their share of the contribution of approximately $170
million for Pepco, $10 million for DPL and $60 million for ACE. PHI
Service Company is responsible to fund the remaining share of the
contribution. PHI will monitor the markets and evaluate any
additional discretionary funding needs later in the year. See Note
(10), “Pensions and Other Postretirement Benefits.”
(2) SIGNIFICANT
ACCOUNTING POLICIES
Consolidation
Policy
The accompanying consolidated financial
statements include the accounts of Pepco Holdings and its wholly owned
subsidiaries. All material intercompany balances and transactions
between subsidiaries have been eliminated. Pepco Holdings uses the
equity method to report investments, corporate joint ventures, partnerships, and
affiliated companies in which it holds a 20% to 50% voting interest and cannot
exercise control over the operations and policies of the
investment. Undivided interests in several jointly owned electric
plants previously held by
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PHI, and
certain transmission and other facilities currently held, are consolidated in
proportion to PHI’s percentage interest in the facility.
Consolidation of Variable
Interest Entities
In accordance with the provisions of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R
entitled “Consolidation of Variable Interest Entities” (FIN 46R), Pepco Holdings
consolidates those variable interest entities where Pepco Holdings or a
subsidiary has been determined to be primary beneficiary. FIN 46R
addresses conditions under which an entity should be consolidated based upon
variable interests rather than voting interests. Subsidiaries of
Pepco Holdings have power purchase agreements (PPAs) with a number of entities
to which FIN 46R applies.
Pepco
and ACE PPAs
Pepco Holdings, through its ACE
subsidiary, is a party to three PPAs with unaffiliated, non-utility generators
(NUGs). Due to a variable element in the pricing structure of the
NUGs, Pepco Holdings potentially assumes the variability in the operations of
the plants related to the NUGs and, therefore, has a variable interest in the
counterparties. In accordance with the provisions of FIN 46R, Pepco
Holdings continued, during 2008, to conduct exhaustive efforts to obtain
information from these three entities, but was unable to obtain sufficient
information to conduct the analysis required under FIN 46R to determine whether
these three entities were variable interest entities or if the Pepco Holdings
subsidiaries were the primary beneficiary. As a result, Pepco
Holdings has applied the scope exemption from the application of FIN 46R for
enterprises that have conducted exhaustive efforts to obtain the necessary
information, but have not been able to obtain such information.
Net purchase activities with the NUGs
for the years ended December 31, 2008, 2007, and 2006, were approximately $349
million, $327 million, and $324 million, respectively, of which approximately
$305 million, $292 million, and $288 million, respectively, related to power
purchases under the NUGs. Pepco Holdings does not have loss exposure
under the NUGs because cost recovery will be achieved from ACE’s customers
through regulated rates.
During
the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP
(Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was
obligated to purchase from Panda 230 megawatts of capacity and energy annually
through 2021 (Panda PPA). Net purchase activities under the Panda PPA
for the years-ended December 31, 2008, 2007 and 2006 were approximately $59
million, $85 million and $79 million, respectively. See Note (16),
“Commitments and Contingencies — Regulatory and Other Matters — Proceeds from
Settlement of Mirant Bankruptcy Claims.”
DPL
Onshore Wind Transactions
In 2008,
DPL entered into three onshore wind PPAs for energy and renewable energy credits
(RECs) to help serve a portion of its requirements under the State of Delaware’s
Renewable Energy Portfolio Standards Act, which requires that 20 percent of
total load needed in Delaware be produced from renewable sources by
2019. The Delaware Public Service Commission (DPSC) has approved all
three agreements, and payments under the agreements are expected to start in
2009 at the earliest.
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DPL has
exclusive rights to the energy and RECs in amounts up to a total between 120 and
150 megawatts under the PPAs. The lengths of the contracts range
between 15 and 20 years. DPL is only obligated to purchase energy and
RECs in amounts generated and delivered by the sellers at rates that are
primarily fixed. Recent disruptions in the capital and credit markets
could result in delays in the start dates for these PPAs. If the PPAs
are not initiated by the specified dates, DPL has the right to terminate the
PPAs. DPL’s maximum exposure to loss under the PPAs is the extent to
which the market prices for energy and RECs fall below the contractual purchase
price.
DPL
concluded that two of the PPAs were leases in accordance with the guidance in
Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an
Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets
under the lease during construction in accordance with EITF Issue No. 97-10,
“The Effect of Lessee Involvement in Asset Construction.” DPL concluded
that it is not the primary beneficiary under the third PPA because it will only
receive 50 percent of the output from the facility and it will not absorb a
majority of the risks or rewards as compared to the debt and equity investors in
the facility. DPL concluded that consolidation is not required for
any of these PPAs under FIN 46(R).
Use of
Estimates
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States
of America (GAAP) requires management to make certain estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses,
and related disclosures of contingent assets and liabilities in the consolidated
financial statements and accompanying notes. Although Pepco Holdings
believes that its estimates and assumptions are reasonable, they are based upon
information available to management at the time the estimates are made. Actual
results may differ significantly from these estimates.
Significant matters that involve the
use of estimates include the assessment of goodwill and long-lived assets for
impairment, fair value calculations for certain derivative instruments, the
costs of providing pension and other postretirement benefits, evaluation of the
probability of recovery of regulatory assets, and the recognition of income tax
benefits as it relates to investments in finance leases held in trust associated
with PHI’s portfolio of cross-border energy sale-leaseback
investments. Additionally, PHI is subject to legal, regulatory, and
other proceedings and claims that arise in the ordinary course of its
business. PHI records an estimated liability for these proceedings
and claims, when the loss is determined to be probable and is reasonably
estimable.
Changes in Accounting
Estimates
As
further discussed in Note (8), “Leasing Activities,” Note (12), “Income Taxes,”
and Note (16), “Commitments and Contingencies — PHI’s Cross-Border Energy Lease
Investments,” PHI maintains a portfolio of cross-border energy sale-leaseback
investments. The book equity value of these cross-border energy lease
investments and the pattern of recognizing the related cross-border energy lease
income are based on the timing and amount of all cash flows related to the
cross-border energy lease investments, including income tax-related cash
flows. These investments are more commonly referred to as
sale-in/lease-out (SILO)
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transactions. PHI
currently derives tax benefits from these investments based on the extent to
which rental income is exceeded by depreciation deductions on the purchase price
of the assets and interest deductions on the non-recourse debt financing
(obtained to fund a substantial portion of the purchase price of the
assets). The Internal Revenue Service (IRS) has announced broadly its
intention to disallow the tax benefits recognized by all taxpayers on these
types of investments, and, more specifically, the IRS has disallowed interest
and depreciation deductions claimed by PHI related to its investments on the
2001 and 2002 PHI federal income tax returns currently under audit and has
sought to recharacterize the leases as loan transactions as to which PHI would
be subject to original issue discount income.
In 2008, several court decisions in
favor of the IRS disallowed deductions in cases involving other taxpayers with
certain cross-border energy lease investments. Under FIN 48,
“Accounting for Uncertainty in Income Taxes,” the financial statement
recognition of an uncertain tax position is permitted only if it is more likely
than not that the position will be sustained. Further, under FASB
Staff Position (FSP) No. 13-2, “Accounting for a Change in the Timing of Cash
Flows Relating to Income Taxes Generated by a Leveraged-Lease Transaction” (FSP
13-2), a company is required to assess on a periodic basis the likely outcome of
tax positions relating to its cross-border energy lease investments and, if
there is a change or a projected change in the estimated timing of the tax
benefits generated from these investments, a recalculation of the value of its
equity investment is required.
While PHI believes that its tax
position with regard to its cross-border energy lease investments is appropriate
based on applicable statutes, regulations and case law and intends to contest
the adjustments proposed by the IRS, after evaluating the court rulings
described above, PHI, at June 30, 2008, reassessed the sustainability of
its tax position and revised its assumptions regarding the estimated timing of
the tax benefits generated from its cross-border energy lease
investments. Based on this reassessment, for the quarter ended
June 30, 2008, PHI recorded an after-tax charge to net income of $93
million, consisting of the following components:
·
A
non-cash pre-tax charge of $124 million ($86 million after tax) under
FSP 13-2 to reduce the equity value of these cross-border energy
lease investments. This pre-tax charge was recorded in the
Consolidated Statement of Earnings as a reduction in other operating
revenue.
·
A
non-cash after-tax charge of $7 million to reflect the anticipated
additional interest expense under FIN 48 related to estimated federal and
state income tax obligations for the period over which the tax benefits
may be disallowed (January 1, 2001 through June 30,2008). This after-tax charge was recorded in the Consolidated
Statement of Earnings as an increase in income tax
expense.
The charge pursuant to FSP 13-2
reflected changes to the book equity value of the cross-border energy lease
investments and the pattern of recognizing the related cross-border energy lease
income. This amount is being recognized as income over the remaining
term of the affected leases, which expire between 2017 and 2047. The
tax benefits associated with the lease transactions represent timing differences
that do not change the aggregate amount of lease net income over the life of the
transactions. No additional charges were considered necessary in the third and
fourth quarters of 2008.
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During 2007, as a result of
depreciation studies presented as part of Pepco’s and DPL’s Maryland rate cases,
the Maryland Public Service Commission (MPSC) approved new, lower depreciation
rates for Maryland distribution assets owned by Pepco and DPL. This
resulted in lower depreciation expense of approximately $19 million in
2007.
Revenue
Recognition
Regulated
Revenue
The Power Delivery businesses recognize
revenue upon delivery of electricity and gas to their customers, including
amounts for services rendered but not yet billed (unbilled
revenue). Pepco Holdings recorded amounts for unbilled revenue of
$195 million and $170 million as of December 31, 2008 and 2007,
respectively. These amounts are included in “Accounts
receivable.” Pepco Holdings’ utility subsidiaries calculate unbilled
revenue using an output based methodology. This methodology is based
on the supply of electricity or gas intended for distribution to
customers. The unbilled revenue process requires management to make
assumptions and judgments about input factors such as customer sales mix,
temperature and estimated power line losses (estimates of electricity expected
to be lost in the process of its transmission and distribution to customers),
all of which are inherently uncertain and susceptible to change from period to
period, and if the actual results differ from the projected results, the impact
could be material.
Taxes related to the consumption of
electricity and gas by the utility customers, such as fuel, energy, or other
similar taxes, are components of the tariff rates charged by PHI subsidiaries
and, as such, are billed to customers and recorded in “Operating
Revenues.” Accruals for these taxes are recorded in “Other
taxes.” Excise tax related generally to the consumption of gasoline
by PHI and its subsidiaries in the normal course of business is charged to
operations, maintenance or construction, and is de minimis.
Competitive
Revenue
The Competitive Energy businesses
recognize revenue upon delivery of electricity and gas to the customer,
including amounts for electricity and gas delivered, but not yet
billed. ISO sales and purchases of electric power are netted hourly
and classified as operating revenue or operating expenses, as
appropriate. Unrealized derivative gains and losses are recognized in
current earnings as revenue if the derivative activity does not qualify for
hedge accounting or normal sales treatment under Statement of Financial
Accounting Standards (SFAS) No. 133. Revenue for Pepco Energy
Services’ energy efficiency construction business is recognized using the
percentage-of-completion method, which recognizes revenue as work is completed
on the contract, and revenues from its operation and maintenance and other
products and services contracts are recognized when earned. Revenue
from the Other Non-Regulated business lines is principally recognized when
services are performed or products are delivered; however, revenues from utility
industry services contracts are recognized using the percentage-of-completion
method.
Taxes Assessed by a
Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco Holdings’ gross
revenues were $311 million, $318 million and $260 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
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Accounting for
Derivatives
Pepco Holdings and its subsidiaries use
derivative instruments primarily to manage risk associated with commodity prices
and interest rates. Risk management policies are determined by PHI’s
Corporate Risk Management Committee (CRMC). The CRMC monitors
interest rate fluctuation, commodity price fluctuation, and credit risk
exposure, and sets risk management policies that establish limits on unhedged
risk.
PHI accounts for its derivative
activities in accordance with SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended. SFAS No. 133
requires derivative instruments to be measured at fair value. Derivatives are
recorded on the Consolidated Balance Sheets as other assets or other liabilities
unless designated as “normal purchases and sales.”
Mark-to-market gains and losses on
derivatives that are not designated as hedges are presented on the Consolidated
Statements of Earnings as operating revenue. PHI uses mark-to-market
accounting through earnings for derivatives that either do not qualify for hedge
accounting or that management does not designate as hedges.
The gain or loss on a derivative that
hedges exposure to variable cash flow of a forecasted transaction is initially
recorded in Other Comprehensive Income (a separate component of common
stockholders’ equity) and is subsequently reclassified into earnings in the same
category as the item being hedged when the gain or loss from the forecasted
transaction occurs. If a forecasted transaction is no longer
probable, the deferred gain or loss in accumulated other comprehensive income is
immediately reclassified to earnings. Gains or losses related to any
ineffective portion of cash flow hedges are also recognized in earnings
immediately as operating revenue or as a Fuel and Purchased Energy
expense.
Changes in the fair value of
derivatives designated as fair value hedges as well as changes in the fair value
of the hedged asset, liability, or firm commitment are recorded in the
Consolidated Statements of Earnings as operating revenue.
PHI designates certain commodity
forwards as “normal purchase or normal sales” under SFAS No. 133, which are not
required to be recorded on a mark-to-market basis of accounting under SFAS No.
133. This type of contract is used in normal operations, settles
physically, and follows standard accrual accounting. Unrealized gains
and losses on these contracts do not appear on the Consolidated Balance
Sheets. Examples of these transactions include purchases of fuel to
be consumed in power plants and actual receipts and deliveries of electric
power. Normal purchases and sales transactions are presented on a
gross basis, with normal sales recorded as operating revenue and normal
purchases recorded as fuel and purchased energy expenses.
The fair value of derivatives is
determined using quoted exchange prices where available. For
instruments that are not traded on an exchange, pricing services and external
broker quotes are used to determine fair value. For some custom and
complex instruments, internal models are used to interpolate broker quality
price information. For certain long-dated instruments, broker or exchange data
is extrapolated for future periods where limited market information is
available. Models are also used to estimate volumes for certain
transactions. See Note (15), “Fair Value
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Disclosures,”
for more information about the types of derivatives employed by PHI and the
methodologies used to value them.
The impact of derivatives that are
marked-to-market through current earnings, the ineffective portion of cash flow
hedges, and the portion of fair value hedges that flows to current earnings are
presented on a net basis in the Consolidated Statements of Earnings as operating
revenue or as a Fuel and Purchased Energy expense. When a hedging
gain or loss is realized, it is presented on a net basis in the same line item
as the underlying item being hedged. Normal purchase and sale
transactions are presented gross on the Consolidated Statements of Earnings as
they are realized. Unrealized derivative gains and losses are
presented gross on the Consolidated Balance Sheets except where contractual
netting agreements are in place with individual counterparties.
Stock-Based
Compensation
Pepco Holdings adopted and implemented
SFAS No. 123R, on January 1, 2006, using the modified prospective
method. Under this method, Pepco Holdings recognizes compensation
expense for share-based awards, modifications or cancellations after the
effective date, based on the grant-date fair value. Compensation
expense is recognized over the requisite service period. In addition,
compensation cost recognized includes the cost for all share-based awards
granted prior to, but not yet vested as of, January 1, 2006, measured at
the grant-date fair value. A deferred tax asset and deferred tax
benefit are also recognized concurrently with compensation expense for the tax
effect of the deduction of stock options and restricted stock awards, which are
deductible only upon exercise and vesting/release from restriction,
respectively. No modifications were made to outstanding stock options or
restricted stock awards outstanding prior to the adoption of SFAS No.123R and no
changes in valuation methodology or assumptions in estimating their fair value
have occurred with its adoption. There were no cumulative adjustments
recorded in the financial statements as a result of this new pronouncement; the
percentage of forfeitures of outstanding stock options issued prior to SFAS No.
123R’s adoption is estimated to be zero.
In
November 2005, the FASB issued FSP 123(R)-3, “Transition Election Related to
Accounting for the Tax Effects of Share-Based Payment Awards” (FSP
123R-3). FSP 123R-3 provides an elective alternative transition
method that includes a computation that establishes the beginning balance of the
additional paid-in capital (APIC pool) related to the tax effects of employee
and director stock-based compensation, and a simplified method to determine the
subsequent impact on the APIC pool of employee and director stock-based awards
that are outstanding upon adoption of SFAS No. 123R. Entities may
make a one-time election to apply the transition method discussed in FSP
123R-3. That one-time election may be made within one year of an
entity’s adoption of SFAS No. 123R, or the FSP’s effective date (November 11,2005), whichever is later. Pepco Holdings adopted the alternative
transition method at December 31, 2006.
Pepco Holdings estimates the fair value
of each stock option award on the date of grant using the Black-Scholes-Merton
option pricing model. This model uses assumptions related to expected
option term, expected volatility, expected dividend yield, and risk-free
interest rate. Pepco Holdings uses historical data to estimate option
exercise and employee termination within the valuation model; separate groups of
employees that have similar historical exercise behavior are considered
separately for valuation purposes. The expected term of options
granted is
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derived
from the output of the option valuation model and represents the period of time
that options granted are expected to be outstanding.
As of January 1, 2008, there were
no outstanding options that were not fully vested. Consequently, no
compensation cost related to the vesting of options was recorded in
2008. Cash received from stock options exercised under all
share-based payment arrangements for the years ended December 31, 2008, 2007 and
2006, was $3 million, $13 million, and $16 million, respectively. The
actual tax benefit realized from these option exercises totaled zero, $1
million, and $1 million, respectively, for the years ended December 31, 2008,
2007 and 2006.
PHI has
issued both time-based and performance-based restricted stock awards that vest
over a three year period. The compensation expense associated with
these awards is based upon estimated fair value at grant date and is recognized
over the three-year service period. The time-based awards have been
issued beginning with the 2006-2008 period, and vest in full at the end of the
three-year period. The performance-based restricted stock awards for
the 2005-2007 performance period contained market conditions that determine the
number of shares issuable upon vesting. The market conditions were
based on PHI’s total shareholder return relative to a peer group of companies
and were reflected in the estimated grant date fair value using a Monte Carlo
simulation. The assumptions used in this valuation method included
risk free interest rates, expected PHI common stock volatility, and expected
correlation to estimate the number of shares to be issued upon
vesting. The expected volatility and correlation inputs were based on
PHI’s and the peer companies’ shareholder returns over a three-year look back
period from the valuation date.
Pepco Holdings’ current policy is to
issue new shares to satisfy stock option exercises and the vesting of restricted
stock awards.
Income
Taxes
PHI and the majority of its
subsidiaries file a consolidated federal income tax return. Federal
income taxes are allocated among PHI and the subsidiaries included in its
consolidated group pursuant to a written tax sharing agreement, which was
approved by the Securities and Exchange Commission (SEC) in connection with the
establishment of PHI as a holding company as part of Pepco’s acquisition of
Conectiv on August 1, 2002. Under this tax sharing agreement, PHI’s
consolidated federal income tax liability is allocated based upon PHI’s and its
subsidiaries’ separate taxable income or loss amounts.
In 2006, the FASB issued FIN 48,
“Accounting for Uncertainty in Income Taxes.” FIN 48 clarifies
the criteria for recognition of tax benefits in accordance with SFAS No. 109,
“Accounting for Income Taxes,” and prescribes a financial statement recognition
threshold and measurement attribute for a tax position taken or expected to be
taken in a tax return. Specifically, it clarifies that an entity’s
tax benefits must be “more likely than not” of being sustained prior to
recording the related tax benefit in the financial statements. If the
position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FSP FIN
48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which
provides guidance on how an enterprise should determine whether a tax position
is effectively settled for the purpose of recognizing previously
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unrecognized
tax benefits. PHI applied the guidance of FIN 48-1 with its adoption
of FIN 48 on January 1, 2007.
The consolidated financial statements
include current and deferred income taxes. Current income taxes
represent the amounts of tax expected to be reported on PHI’s and its
subsidiaries’ federal and state income tax returns. Deferred income
tax assets and liabilities represent the tax effects of temporary differences
between the financial statement and tax basis of existing assets and liabilities
and are measured using presently enacted tax rates. See Note (12),
“Income Taxes” for a listing of primary deferred tax assets and
liabilities. The portion of Pepco’s, DPL’s, and ACE’s deferred tax
liability applicable to its utility operations that has not been recovered from
utility customers represents income taxes recoverable in the future and is
included in “Regulatory assets” on the Consolidated Balance
Sheets. See Note (7), “Regulatory Assets and Regulatory Liabilities,”
for additional information.
PHI recognizes interest on under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense. Deferred income tax expense
generally represents the net change during the reporting period in the net
deferred tax liability and deferred recoverable income taxes.
Investment tax credits from utility
plants purchased in prior years are reported on the Consolidated Balance Sheets
as “Investment tax credits.” These investment tax credits are being
amortized to income over the useful lives of the related utility plant.
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, cash invested in money market funds, and commercial paper held with
original maturities of three months or less.
Restricted Cash
Equivalents
The restricted cash equivalents
included in Current Assets and the restricted cash equivalents included in
Investments and Other Assets represent (i) cash held as collateral that is
restricted from use for general corporate purposes and (ii) cash
equivalents that are specifically segregated, based on management’s intent to
use such cash equivalents. The classification as current or non-current conforms
to the classification of the related liabilities.
Accounts Receivable and
Allowance for Uncollectible Accounts
Pepco Holdings’ accounts receivable
balances primarily consist of customer accounts receivable, other accounts
receivable, and accrued unbilled revenue generated by subsidiaries in the Power
Delivery and Competitive Energy businesses. Accrued unbilled revenue
represents revenue earned in the current period but not billed to the customer
until a future date (usually within one month after the receivable is
recorded).
PHI
maintains an allowance for uncollectible accounts and changes in the allowance
are recorded as an adjustment to Other Operation and Maintenance expense in the
Consolidated Statements of Earnings. PHI determines the amount of the
allowance based on specific identification of material amounts at risk by
customer and maintains a general reserve based on its historical collection
experience. The adequacy of this allowance is assessed on a quarterly
basis by evaluating all known factors, such as the aging of the receivables,
historical collection
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experience,
the economic and competitive environment, and changes in the creditworthiness of
its customers. Although management believes its allowance is adequate, it cannot
anticipate with any certainty the changes in the financial condition of its
customers. As a result, PHI records adjustments to the allowance for
uncollectible accounts in the period the new information is known.
Inventories
Inventory
is valued at the lower of cost or market value. Included in inventories
are:
- generation,
transmission, and distribution materials and supplies;
- natural
gas, fuel oil, and coal; and
- emission
allowances, renewable energy credits and RGGI allowances.
PHI
utilizes the weighted average cost method of accounting for inventory items,
other than fuel oil held for resale. Under this method, an average price is
determined for the quantity of units acquired at each price level and is applied
to the ending quantity to calculate the total ending inventory balance.
Materials and supplies inventory are generally charged to inventory when
purchased and then expensed or capitalized to plant, as appropriate, when
installed.
The cost
of natural gas, coal, and fuel oil for power plants, including transportation
costs, are included in inventory when purchased and charged to fuel expense when
used. The first in first out (FIFO) method is used for fuel oil
inventory held for resale in Conectiv Energy’s oil marketing business. The FIFO
method is not materially different from the weighted average cost method for PHI
due to the high inventory turnover rate in the oil marketing
business.
Emission
allowances from United States Environmental Protection Agency (EPA) allocations
are added to current inventory each year at a zero cost. Purchased
emission allowances are recorded at cost. Emission allowances sold or
consumed at the power plants are expensed at a weighted-average
cost. This cost tends to be relatively low due to the inclusion of
the zero-basis allowances. At December 31, 2008 and 2007, the
book value of emission allowances was $11 million and $9 million,
respectively. Pepco Holdings has established a committee to monitor
compliance with emissions regulations and to ensure its power plants have the
required number of allowances.
At
December 31, 2008, the market value of Conectiv Energy’s oil inventory was lower
than cost and accordingly a pre-tax charge of $15 million was
recorded. This charge is included in Fuel and Purchased Energy in the
Consolidated Statements of Earnings.
Goodwill
Goodwill
represents the excess of the purchase price of an acquisition over the fair
value of the net assets acquired at the acquisition
date. Substantially all of Pepco Holdings’ goodwill was generated by
Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’
Power Delivery reporting unit based on the aggregation of its
components. Pepco Holdings tests its goodwill for impairment annually
as of July 1, and whenever an event occurs or circumstances change in the
interim that would more likely than not reduce the fair value of a reporting
unit below its carrying amount. Factors that may result in an interim impairment
test include, but are not limited to: a change in the identified reporting
units; an adverse change in
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business
conditions; a protracted decline in stock price causing market capitalization to
fall below book value; an adverse regulatory action; or an impairment of
long-lived assets in the reporting unit. PHI performed its annual
impairment test on July 1, 2008 and an interim impairment test at
December 31, 2008, and no impairment was recorded as described in Note (6),
“Goodwill.”
Regulatory Assets and
Regulatory Liabilities
The Power Delivery operations of Pepco
are regulated by the District of Columbia Public Service Commission (DCPSC) and
the MPSC.
The Power Delivery operations of DPL
are regulated by the DPSC and the MPSC and, until the sale of its Virginia
assets on January 2, 2008, were also regulated by the Virginia State
Corporation Commission (VSCC). DPL’s interstate transportation and
wholesale sale of natural gas are regulated by the Federal Energy Regulatory
Commission (FERC).
The Power Delivery operations of ACE
are regulated by the New Jersey Board of Public Utilities (NJBPU).
The transmission and wholesale sale of
electricity by Pepco, DPL, and ACE are regulated by FERC.
The requirements of SFAS No. 71 apply
to the Power Delivery businesses of Pepco, DPL, and ACE. SFAS No. 71 allows
regulated entities, in appropriate circumstances, to establish regulatory assets
and liabilities and to defer the income statement impact of certain costs that
are expected to be recovered in future rates. Management’s assessment of the
probability of recovery of regulatory assets requires judgment and
interpretation of laws, regulatory commission orders, and other
factors. If management subsequently determines, based on changes in
facts or circumstances, that a regulatory asset is not probable of recovery,
then the regulatory asset will be eliminated through a charge to
earnings.
As part of the new electric service
distribution base rates for Pepco and DPL approved by the MPSC, effective in
June 2007, the MPSC approved for both companies a bill stabilization adjustment
mechanism (BSA) for retail customers. See Note (16) “Commitments and
Contingencies — Regulatory and Other Matters — Rate Proceedings.” For
customers to which the BSA applies, Pepco and DPL recognize distribution revenue
based on an approved distribution charge per customer. From a revenue
recognition standpoint, the BSA thus decouples the distribution revenue
recognized in a reporting period from the amount of power delivered during the
period. Pursuant to this mechanism, Pepco and DPL recognize either
(a) a positive adjustment equal to the amount by which revenue from Maryland
retail distribution sales falls short of the revenue that Pepco and DPL are
entitled to earn based on the approved distribution charge per customer, or (b)
a negative adjustment equal to the amount by which revenue from such
distribution sales exceeds the revenue that Pepco and DPL are entitled to earn
based on the approved distribution charge per customer (a Revenue Decoupling
Adjustment). A positive Revenue Decoupling Adjustment is recorded as
a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a
regulatory liability. The net Revenue Decoupling Adjustment at
December 31, 2008 is a regulatory asset and is included in the “Other” line item
on the table of regulatory asset balances in Note (7), “Regulatory Assets and
Regulatory Liabilities.”
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Leasing
Activities
Pepco Holdings’ lease transactions can
include plant, office space, equipment, software, vehicles, and power purchase
agreements. In accordance with SFAS No. 13, “Accounting for Leases”
(SFAS No. 13), these leases are classified as either capital leases,
operating leases or leveraged leases. In addition, PHI assesses whether a power
purchase agreement contains a lease within the scope of SFAS No. 13 using
guidance in EITF Issue No. 01-08, “Determining Whether an Arrangement
Contains a Lease.”
Leveraged
Leases
Income
from investments in leveraged lease transactions, in which PHI is an equity
participant, is accounted for using the financing method. In accordance with the
financing method, investments in leased property are recorded as a receivable
from the lessee to be recovered through the collection of future rentals.
Income, including investment tax credits, on leveraged equipment leases is
recognized over the life of the lease at a constant rate of return on the
positive net investment. Each quarter, PHI reviews the carrying value of each
lease, which includes a review of the underlying lease financial assumptions,
the timing and collectability of cash flows, and the credit quality (including,
if available, credit ratings) of the lessee. Changes to the
underlying assumptions, if any, would be accounted for in accordance with SFAS
No. 13 and reflected in the carrying value of the lease effective for the
quarter within which they occur.
Operating
Leases
An
operating lease generally results in a level income statement charge over the
term of the lease, reflecting the rental payments required by the lease
agreement. If rental payments are not made on a straight-line basis,
PHI’s policy is to recognize the increases on a straight-line basis over the
lease term unless another systematic and rational allocation basis is more
representative of the time pattern in which the leased property is physically
employed.
Capital
Leases
For
ratemaking purposes, capital leases are treated as operating leases; therefore,
in accordance with SFAS No. 71, the amortization of the leased asset is
based on the rental payments recovered from customers. Investments in equipment
under capital leases are stated at cost, less accumulated depreciation.
Depreciation is recorded on a straight-line basis over the equipment’s estimated
useful life.
Arrangements
Containing a Lease
PPAs
might fall within the criteria of contracts containing a lease if the
arrangement conveys the right to use and control property, plant or
equipment. If so, PHI is required to determine whether capital or
operating lease accounting is appropriate under SFAS No. 13.
Property, Plant and
Equipment
Property, plant and equipment are
recorded at original cost, including labor, materials, asset retirement costs,
and other direct and indirect costs including capitalized
interest. The carrying value of property, plant and equipment is
evaluated for impairment whenever
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circumstances
indicate the carrying value of those assets may not be recoverable under the
provisions of SFAS No. 144. Upon retirement, the cost of regulated
property, net of salvage, is charged to accumulated depreciation. For
non-regulated property, the cost and accumulated depreciation of the property,
plant and equipment retired or otherwise disposed of are removed from the
related accounts and included in the determination of any gain or loss on
disposition.
The annual provision for depreciation
on electric and gas property, plant and equipment is computed on a straight-line
basis using composite rates by classes of depreciable
property. Accumulated depreciation is charged with the cost of
depreciable property retired, less salvage and other
recoveries. Property, plant and equipment, other than electric and
gas facilities, is generally depreciated on a straight-line basis over the
useful lives of the assets. The table below provides system-wide
composite annual depreciation rates for the years ended December 31, 2008, 2007,
and 2006.
Transmission
&
Distribution
Generation
2008
2007
2006
2008
2007
2006
Pepco
2.7%
3.0%
3.5%
-
-
-
DPL
2.8%
2.9%
3.0%
-
-
-
ACE
2.8%
2.9%
2.9%
-
-
.3%(a)
Conectiv
Energy
-
-
-
2.0%
2.0%
2.0%
Pepco
Energy Services
-
-
-
9.5%
10.1%
9.6%
(a)
Rate
reflects the Consolidated Balance Sheet classification of ACE’s generation
assets as “assets held for sale” in 2006 and, therefore, de minimis
depreciation expense was recorded.
In accordance with FSP American
Institute of Certified Public Accountants Industry Audit Guide, Audits of
Airlines—”Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1),
costs associated with planned major maintenance activities related to generation
facilities are expensed as incurred.
Long-Lived Assets
Impairment
Pepco Holdings evaluates long-lived
assets to be held and used, such as generating property and equipment and real
estate, to determine if they are impaired whenever events or changes in
circumstances indicate that their carrying amount may not be
recoverable. Examples of such events or changes include a significant
decrease in the market price of a long-lived asset or a significant adverse
change in the manner in which an asset is being used or its physical
condition. A long-lived asset to be held and used is written down to
fair value if the sum of its expected future undiscounted cash flows is less
than its carrying amount.
For long-lived assets held for sale, an
impairment loss is recognized to the extent that the assets’ carrying amount
exceeds their fair value including costs to sell.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, PHI’s utility subsidiaries can capitalize as Allowance for Funds
Used During Construction (AFUDC) the capital costs of financing the construction
of plant and equipment. The debt portion of AFUDC is recorded as
a
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reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Consolidated Statements of Earnings.
Pepco Holdings recorded AFUDC for
borrowed funds of $5 million, $7 million, and $3 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Pepco Holdings recorded amounts for the
equity component of AFUDC of $5 million, $4 million and $4 million for the years
ended December 31, 2008, 2007, and 2006, respectively.
Amortization of Debt
Issuance and Reacquisition Costs
Pepco Holdings defers and amortizes
debt issuance costs and long-term debt premiums and discounts over the lives of
the respective debt issues. Costs associated with the redemption of
debt for PHI’s subsidiaries are also deferred and amortized over the lives of
the new issues.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory defined benefit retirement plan that covers substantially all
employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings
subsidiaries (the PHI Retirement Plan). Pepco Holdings also provides
supplemental retirement benefits to certain eligible executives and key
employees through a nonqualified retirement plan and provides certain
postretirement health care and life insurance benefits for eligible retired
employees.
Pepco Holdings accounts for the PHI
Retirement Plan and nonqualified retirement plans in accordance with
SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132
(R)” (SFAS No. 158), and its postretirement health care and life insurance
benefits for eligible employees in accordance with SFAS No. 106,
“Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as
amended by SFAS No. 158. PHI’s financial statement disclosures are
prepared in accordance with SFAS No. 132, “Employers’ Disclosures
about Pensions and Other Postretirement Benefits,” as amended by SFAS No.
158.
See Note (10), “Pensions and Other
Postretirement Benefits,” for additional information.
Preferred
Stock
As of December 31, 2008 and 2007, PHI
had 40 million shares of preferred stock authorized for issuance, with a par
value of $.01 per share. No shares of preferred stock were
outstanding at December 31, 2008 and 2007.
Reclassifications and
Adjustments
Certain prior year amounts have been
reclassified in order to conform to current year presentation.
During
2008, PHI recorded adjustments to correct errors in Other Operation and
Maintenance expenses for prior periods dating back to February 2005 during
which (i) customer late payment fees were incorrectly recognized and (ii)
stock-based compensation expense related
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PEPCO
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to
certain restricted stock awards granted under the Long-Term Incentive Plan was
understated. These adjustments, which were not considered material either
individually or in the aggregate, resulted in increases in Other Operation and
Maintenance expenses of $15 million for the year ended December 31, 2008,
all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING
STANDARDS
Statement of Financial Accounting
Standards (SFAS) No. 157, “Fair Value Measurements”
(SFAS No.
157)
SFAS No. 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies to
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. Under SFAS No.
157, fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants in
the most advantageous market using the best available information. The
provisions of SFAS No. 157 were effective for financial statements beginning
January 1, 2008 for PHI.
In
February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157
to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair
Value Measurements for Purposes of Lease Classification or Measurement under
Statement 13” (FSP 157-1), that removed fair value measurement for the
recognition and measurement of lease transactions from the scope of SFAS No.
157. The effective date of FSP 157-1 was for financial statement
periods beginning January 1, 2008 for PHI.
Also in
February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement
No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all
non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually), until financial statement reporting periods
beginning January 1, 2009 for PHI.
PHI applied the guidance of FSP 157-1
and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS
No. 157 on January 1, 2008 did not result in a transition adjustment to
beginning retained earnings and did not have a material impact on PHI’s overall
financial condition, results of operations, or cash flows. SFAS No.
157 also required new disclosures regarding the level of pricing observability
associated with financial instruments carried at fair value. This
additional disclosure is provided in Note (15), “Fair Value
Disclosures.” PHI is currently evaluating the impact of FSP 157-2 and
does not anticipate that the application of FSP 157-2 to its other non-financial
assets and non-financial liabilities will materially affect its overall
financial condition, results of operations, or cash flows.
In September 2008, the SEC and
FASB issued guidance on fair value measurements, which was clarified in
October 2008 by the FASB in FSP 157-3, “Determining the Fair Value of a
Financial Asset When the Market for that Asset is Not Active.” This
guidance clarifies the application of SFAS No. 157 to assets in an inactive
market and illustrates how to determine the fair value of a financial asset in
an inactive market. The guidance was effective beginning with the
September 30, 2008 reporting period for PHI, and has not had a material
impact on PHI’s results.
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SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities—including an Amendment of FASB Statement No.
115” (SFAS No.
159)
SFAS No. 159 permits entities to elect
to measure eligible financial instruments at fair value. SFAS No. 159
applies to other accounting pronouncements that require or permit fair value
measurements and does not require any new fair value measurements. On
January 1, 2008, PHI elected not to apply the fair value option for its
eligible financial assets and liabilities.
FASB Staff Position (FSP) FIN 39-1,
“Amendment of FASB Interpretation No. 39” (FSP FIN 39-1)
FSP FIN 39-1 amended certain portions
of FIN 39. The FSP replaces the terms “conditional contracts” and “exchange
contracts” in FIN 39 with the term “derivative instruments” as defined in SFAS
No. 133. The FSP also amends FIN 39 to allow for the offsetting
of fair value amounts for the right to reclaim cash collateral or receivables,
or the obligation to return cash collateral or payables, arising from the same
master netting arrangement as the derivative instruments. FSP FIN 39-1
applied to financial statements beginning January 1, 2008 for
PHI.
PHI retrospectively adopted the
provisions of FSP FIN 39-1 and elected to offset the net fair value amounts
recognized for derivative instruments and fair value amounts recognized for
related collateral positions executed with the same counterparty under a master
netting arrangement. Additional disclosure of collateral positions
that have been offset against net derivative positions is provided in Note (17),
“Use of Derivatives in Energy and Interest Rate Hedging
Activities.” The effect of retrospective application of FSP FIN 39-1
was not material at December 31, 2007 and, as such, no amounts were
reclassified.
Emerging Issues Task Force (EITF) Issue
No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based
Payment Awards” (EITF 06-11)
EITF 06-11 provides that a realized
income tax benefit from dividends or dividend equivalents that are charged to
retained earnings and paid to employees for equity classified non-vested equity
shares, non-vested equity share units, and outstanding equity share options
should be recognized as an increase to additional paid-in capital
(APIC). The amount recognized in APIC for the realized income tax
benefit from dividends on those awards should be included in the pool of excess
tax benefits available to absorb tax deficiencies on share-based payment
awards. If the estimated amount of forfeitures increases or actual
forfeitures reduce the amount of tax benefits previously recognized in APIC and
if the APIC pool is depleted, then the reduction in tax benefit would be an
adjustment to the income statement.
EITF 06-11 applied prospectively to the
income tax benefits of dividends on equity-classified employee share-based
payment awards that are granted during financial statement reporting periods
beginning on January 1, 2008 for PHI. PHI adopted the provisions
of EITF 06-11 on January 1, 2008, and it did not have a material
impact on PHI’s overall financial condition, results of operations, or cash
flows.
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SFAS No. 162, “The Hierarchy of
Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS
No. 162, which identifies the sources of accounting principles and the hierarchy
for selecting the principles to be used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with
GAAP. Moving the GAAP hierarchy into the accounting literature
directs the responsibility for applying the hierarchy to the reporting entity,
rather than just to the auditors.
SFAS No. 162 was effective for PHI
as of November 15, 2008 and did not result in a change in accounting for
PHI. Therefore, the provisions of SFAS No. 162 did not have a
material impact on PHI’s overall financial condition, results of operations,
cash flows and disclosure.
FSP
FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain
Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued
FSP FAS 133-1 and FIN 45-4, which require enhanced disclosures by entities that
provide credit protection through credit derivatives (including embedded credit
derivatives) within the scope of SFAS No. 133, and guarantees within the scope
of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others.”
For
credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature
and fair value of the credit derivative, the approximate term, the reasons for
entering the derivative, the events requiring performance, and the current
status of the payment/performance risk. It also requires disclosures
of the maximum potential amount of future payments without any reduction for
possible recoveries under collateral provisions, recourse provisions, or
liquidation proceeds. PHI has not provided credit protection to
others through the credit derivatives within the scope of SFAS No.
133.
For
guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status
of the payment/performance risk and whether the current status is based on
external credit ratings or current internal groupings used to manage
risk. If internal groupings are used, then information is required
about how the groupings are determined and used for managing risk.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2008 for PHI. Comparative disclosures are
only required for periods ending after initial adoption. The new
guarantee disclosures did not have a material impact on PHI.
FSP
FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about
Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP
FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP
FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original
pronouncements. The disclosure requirements in SFAS No. 140 for transfers
of financial assets are to include disclosure of (i) a transferor’s continuing
involvement in transferred financial assets, and (ii) how a transfer of
financial assets to a special-
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purpose
entity affects an entity’s financial position, financial performance, and cash
flows. The principal objectives of the disclosure requirements in Interpretation
46(R) are to outline (i) the significant judgments in determining whether an
entity should consolidate a variable interest entity (VIE), (ii) the nature of
any restrictions on consolidated assets, (iii) the risks associated with the
involvement in the VIE, and (iv) how the involvement with the VIE affects an
entity’s financial position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is
effective for PHI’s December 31, 2008 financial statements. This FSP
has no material impact to PHI’s overall financial condition, results of
operations, or cash flows as it relates to SFAS No. 140. PHI’s
FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies
- Consolidation of Variable Interest Entities.”
(4) RECENTLY ISSUED ACCOUNTING
STANDARDS, NOT YET ADOPTED
SFAS No. 141(R) replaces FASB Statement
No. 141, “Business Combinations,” and retains the fundamental requirements that
the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business
combination. However, SFAS No. 141 (R) expands the definition of a
business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer
to recognize changes in the amount of its deferred tax benefits that are
realizable because of a business combination either in income from continuing
operations or directly in contributed capital, depending on the
circumstances.
In
January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and
Liabilities Assumed in a Business Combination that Arise from Contingencies”
(FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and
liabilities arising from contingencies in a business combination. The
FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a
business combination that arise from contingences be measured at fair value in
accordance with SFAS No. 157 if the acquisition date can be reasonably
determined. If not, then the asset or liability would be measured at
the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN
14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance
provided in FSP FAS 141(R)-a applies prospectively to business combinations for
which the acquisition date is on or after January 1, 2009 for
PHI. PHI has evaluated the impact of SFAS No. 141(R) and does
not anticipate its adoption will have a material impact on its overall financial
condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No.
160)
SFAS No. 160 establishes new accounting
and reporting standards for a non-controlling interest (also called a “minority
interest”) in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a minority interest in a subsidiary is
an ownership interest in the consolidated entity that should be separately
reported in the consolidated financial statements.
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SFAS No. 160 establishes accounting and
reporting standards that require (i) the ownership interests and the related
consolidated net income in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, and
presented separately on the face of the consolidated statement of
income, (ii) the changes in a parent’s ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for as
equity transactions, and (iii) when a subsidiary is deconsolidated, any retained
non-controlling equity investment in the former subsidiary must be initially
measured at fair value.
SFAS No. 160 is effective prospectively
for financial statement reporting periods beginning January 1, 2009 for
PHI, except for the presentation and disclosure requirements. The
presentation and disclosure requirements apply retrospectively for all periods
presented. PHI has evaluated the impact of SFAS No. 160
and does not anticipate its adoption will have a material impact on its overall
financial condition, results of operations, cash flows or
disclosure.
SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No.
133” (SFAS No. 161)
In March 2008, the FASB issued
SFAS No. 161, which changes the disclosure requirements for derivative
instruments and hedging activities. Entities will be required to
provide qualitative disclosures about derivatives objectives and strategies,
fair value amounts of gains and losses on derivative instruments which before
were optional, disclosure about credit-risk-related contingent features in
derivative agreements, and information on the potential effect on an entity’s
liquidity from using derivatives.
SFAS No. 161 requires that the gross
fair value of derivative instruments and gross gains and losses be
quantitatively disclosed in a tabular format to provide a more complete picture
of the location in an entity’s financial statements of both the derivative
positions existing at period end and the effect of using derivatives during the
reporting period. The FASB provides an option for hedged items to be
presented in tabular or non-tabular format.
SFAS No. 161 is effective for financial
statement reporting periods beginning January 1, 2009 for
PHI. SFAS No. 161 encourages but does not require disclosures for
earlier periods presented for comparative purposes at initial
adoption. PHI is currently evaluating the impact SFAS No. 161
may have on its March 31, 2009 quarterly disclosures.
FSP
EITF No. 03-6-1, “Determining whether Instruments Granted in Share-Based Payment
Transactions are Participating Securities” (FSP EITF 03-6-1)
In June 2008, the FASB issued FSP
EITF 03-6-1, which addresses whether instruments granted in share-based payment
transactions are participating securities prior to vesting and, therefore, need
to be included in the earnings allocation in computing earnings per share (EPS)
under the two-class method described in SFAS No. 128, “Earnings per
Share.”
FSP EITF 03-6-1 is effective for
financial reporting periods beginning January 1, 2009 for
PHI. All prior period EPS data presented shall be adjusted
retrospectively (including interim financial statements, summaries of earnings,
and selected financial data) to conform with the
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provisions
of FSP EITF 03-6-1. PHI is currently evaluating the impact FSP EITF
03-6-1 will have on its earnings per share calculations.
EITF
Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with
a Third Party Credit Enhancement” (EITF 08-5)
In
September 2008, the FASB issued EITF 08-5 to provide guidelines for the
determination of the unit of accounting for a liability issued with an
inseparable third-party credit enhancement when it is measured or disclosed at
fair value on a recurring basis. EITF 08-5 applies to entities that incur
liabilities with inseparable third-party credit enhancements or guarantees that
are recognized or disclosed at fair value. This would include
guaranteed debt obligations, derivatives, and other instruments that are
guaranteed by third parties.
The
effect of the credit enhancement may not be included in the fair value
measurement of the liability, even if the liability is an inseparable
third-party credit enhancement. The issuer is required to disclose the existence
of the inseparable third-party credit enhancement on the issued
liability.
EITF 08-5
is effective on a prospective basis for reporting periods beginning on and after
January 1, 2009 for PHI. The effect of initial application must be
included in the change in fair value in the period of adoption. PHI
is currently evaluating the impact on its accounting and
disclosures.
In November 2008, the FASB issued EITF
08-6 to address the accounting for equity method investments including: (i) how
an equity method investment should initially be measured, (ii) how it should be
tested for impairment, and (iii) how an equity method investee’s issuance of
shares should be accounted for. The EITF provides that initial
carrying value of an equity method investment can be determined using the
accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and
other-than-temporary impairments should be recognized in accordance with
paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity
Method of Accounting for Investments in Common Stock.”
This EITF
is effective for PHI beginning January 1, 2009. PHI is currently
evaluating the impact on its accounting and disclosures.
FSP
FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP FAS 132(R)-1)
In
December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. The required disclosures under this FSP would
expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about
Pensions and Other Postretirement Benefits—an amendment of FASB Statements No.
87, 88, and 106,” to be in line with SFAS No. 157 required
disclosures.
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The
disclosures are to provide users an understanding of the investment allocation
decisions made, factors used in the investment policies and strategies, plan
assets by major investment types, inputs and valuation techniques used to
measure fair value of plan assets, significant concentration of risk within the
plan, and the effects of fair value measurement using significant unobservable
inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for
the period.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2009 for PHI and earlier application is
permitted. Comparative disclosures under this provision are not
required for earlier periods presented. PHI is currently evaluating
the impact on its disclosures.
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(5) SEGMENT
INFORMATION
Based on the provisions of SFAS No.
131, “Disclosures about Segments of an Enterprise and Related Information,”
Pepco Holdings’ management has identified its operating segments at
December 31, 2008 as Power Delivery, Conectiv Energy, Pepco Energy
Services, and Other Non-Regulated. Segment financial information for
the years ended December 31, 2008, 2007, and 2006, is as
follows:
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition date. For
consolidation purposes, the Total Assets line item in this column includes
Pepco Holdings’ goodwill balance which is primarily attributable to Power
Delivery. Included in Corp. & Other are intercompany
amounts of $(422) million for Operating Revenue, $(417) million for
Operating Expense, $(70) million for Interest Income, $(67) million for
Interest Expense, and $(3) million for Preferred Stock
Dividends.
(b)
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy in the amount of $374 million for the year ended December31, 2008.
(c)
Includes
depreciation and amortization of $377 million, consisting of $317 million
for Power Delivery, $37 million for Conectiv Energy, $13 million for Pepco
Energy Services, $2 million for Other Non-Regulated and $8 million for
Corp. & Other.
(d)
Included
in Operating Revenue is a pre-tax charge of $124 million ($86 million
after-tax) related to the adjustment to the equity value of cross-border
energy lease investments, and included in Income Taxes is a $7 million
after-tax charge for the additional interest accrued on the related tax
obligations.
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition
date. For consolidation purposes, the Total Assets line item in
this column includes Pepco Holdings’ goodwill balance which is primarily
attributable to Power Delivery. Included in Corp. & Other
are intercompany amounts of $(469) million for Operating Revenue, $(464)
million for Operating Expense, $(93) million for Interest Income, $(90)
million for Interest Expense, and $(3) million for Preferred Stock
Dividends.
(b)
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy and Pepco Energy Services in the amount of $431 million
for the year ended December 31,2007.
(c)
Includes
depreciation and amortization of $366 million, consisting of $305 million
for Power Delivery, $38 million for Conectiv Energy, $12 million for Pepco
Energy Services, $2 million for Other Non-Regulated and $9 million for
Corp. & Other.
(d)
Includes
$33 million ($20 million, after-tax) from settlement of Mirant bankruptcy
claims.
(e)
Includes
$20 million benefit ($18 million net of fees) related to Maryland income
tax settlement.
(f)
Includes
stock-based compensation expense of $4 million, consisting primarily of $3
million for Power Delivery and $1 million for Conectiv
Energy.
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition
date. For consolidation purposes, the Total Assets line item in
this column includes Pepco Holdings’ goodwill balance which is primarily
attributable to Power Delivery. Included in Corp. & Other
are intercompany amounts of $(481) million for Operating Revenue, $(475)
million for Operating Expense, $(90) million for Interest Income, $(88)
million for Interest Expense, and $(3) million for Preferred Stock
Dividends.
(b)
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy in the amount of $461 million for the year ended December31, 2006.
(c)
Includes
depreciation and amortization of $413 million, consisting of $354 million
for Power Delivery, $36 million for Conectiv Energy, $12 million for Pepco
Energy Services, $2 million for Other Non-Regulated and $9 million for
Corp. & Other.
(d)
Includes
$12 million gain ($8 million after-tax) on the sale of its equity interest
in a joint venture which owns a wood burning cogeneration facility in
California.
(e)
Includes
$19 million of impairment losses ($14 million after-tax) related to
certain energy services business
assets.
(f)
In
2006, PHI resolved certain, but not all, tax matters that were raised in
Internal Revenue Service audits related to the 2001 and 2002 tax
years. Adjustments recorded related to these resolved tax
matters resulted in a $6 million increase in net income ($3 million for
Power Delivery and $5 million for Other Non-Regulated, partially offset by
an unfavorable $2 million impact in Corp. & Other). To the
extent that the matters resolved related to tax contingencies from the
Conectiv legacy companies that existed at the August 2002 acquisition
date, in accordance with accounting rules, an additional adjustment of $9
million ($3 million related to Power Delivery and $6 million related to
Other Non-Regulated) was recorded in Corp. & Other to eliminate the
tax benefits recorded by Power Delivery and Other Non-Regulated against
the goodwill balance that resulted from the acquisition. Also
during 2006, the total favorable impact of $3 million was recorded that
resulted from changes in estimates related to prior year tax liabilities
subject to audit ($4 million for Power Delivery, partially offset by an
unfavorable $1 million for Corp. &
Other).
(g)
Includes
stock-based compensation expense of $5 million, consisting primarily of $4
million for Power Delivery and $1 million for Conectiv
Energy.
(6) GOODWILL
Substantially
all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002
and is allocated to the Power Delivery reporting unit for purposes of assessing
impairment under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No.
142). PHI’s July 1, 2008 annual impairment test indicated that its
goodwill was not impaired. PHI performed an interim impairment test
at December 31, 2008, as its market capitalization for a significant period in
the fourth quarter of 2008 was lower than its book value. The test at
December 31, 2008 indicated that the goodwill balance was not
impaired.
182
PEPCO
HOLDINGS
To
estimate the fair value of its Power Delivery reporting unit for its goodwill
impairment test, PHI reviewed the results from two discounted cash flow
models. The models differ in the method used to calculate the
terminal value of the reporting unit. One estimate of terminal value
is based on a constant, annual cash flow growth rate that is consistent with
Power Delivery’s plan, and the other estimate of terminal value is based on a
multiple of earnings before interest, taxes, depreciation, and amortization that
management believes is consistent with relevant market multiples for comparable
utilities. Each model uses a cost of capital appropriate for a
regulated utility as the discount rate for the estimated cash flows associated
with the reporting unit. Neither valuation model evidenced impairment
of goodwill. PHI has consistently used this valuation model to
estimate the fair value of Power Delivery since the adoption of SFAS No.
142.
The
estimation of fair value is dependent on a number of factors, including but not
limited to future growth assumptions, operating and capital expenditure
requirements, and capital costs, and changes in these factors could materially
impact the results of impairment testing. The estimated cash flows
were sourced from the Power Delivery reporting unit’s business forecast, and
they incorporate current plans for capital expenditures and regulatory
ratemaking cases. Assumptions and methodologies used in the models
were consistent with historical experience, including assumptions concerning the
recovery of operating costs and capital expenditures. The discount
rate employed reflected PHI’s estimated cost of capital. Sensitive,
interrelated and uncertain variables that could decrease the estimated fair
value of the Power Delivery reporting unit include utility sector market
performance, sustained poor economic conditions, the results of rate-making
proceedings, higher operating and capital expenditure requirements, a
significant increase in the cost of capital and other factors.
PHI
reconciled its total market capitalization at year-end with the sum of the fair
value of its business segments to further substantiate the estimated fair value
of the Power Delivery reporting unit. PHI determined its market
capitalization as of December 31, 2008 for purposes of the reconciliation, which
was 7 percent below book value. PHI estimated the fair value of its
other business segments (Conectiv Energy, Pepco Energy Services, Other
Non-Regulated, and Corporate & Other). The sum of the estimated
fair values of the segments exceeded the market capitalization of PHI at
December 31, 2008. Management believes that the excess fair value is
reflective of a reasonable control premium that reconciles PHI’s market
capitalization to the estimated fair value of its business
segments. The control premium calculated was consistent with control
premiums paid in historical acquisitions in the utility industry.
With the
current volatile general market conditions and the disruptions in the credit and
capital markets, PHI will continue to closely monitor for indicators of goodwill
impairment.
A roll forward of PHI’s goodwill
balance is set forth below (millions of dollars):
The components of Pepco Holdings’
regulatory asset balances at December 31, 2008 and 2007 are as
follows:
2008
2007
(Millions
of dollars)
Securitized
stranded costs
$ 674
$ 735
Pension
and OPEB costs
944
334
Deferred
energy supply costs
31
31
Deferred
income taxes
153
156
Deferred
debt extinguishment costs
72
72
Unrecovered
purchased power contract costs
9
10
Deferred
other postretirement benefit costs
10
13
Phase
in credits
10
39
Other
181
126
Total
Regulatory Assets
$2,084
$1,516
The components of Pepco Holdings’
regulatory liability balances at December 31, 2008 and 2007 are as
follows:
2008
2007
(Millions
of dollars)
Deferred
income taxes due to customers
$ 57
$ 60
Deferred
energy supply costs
257
248
Federal
and New Jersey tax benefits,
related
to securitized stranded costs
28
31
Asset
removal costs
341
332
Excess
depreciation reserve
74
90
Settlement
proceeds — Mirant bankruptcy claims
102
415
Gain
from sale of divested assets
26
67
Other
7
6
Total
Regulatory Liabilities
$892
$1,249
A
description for each category of regulatory assets and regulatory liabilities
follows:
Securitized Stranded
Costs: Represents stranded costs associated with contract
termination payments associated with a contract between ACE and an unaffiliated
non-utility generator (NUG) and the discontinuation of the application of SFAS
No. 71 for ACE’s electricity generation business. The recovery of
these stranded costs has been securitized through the issuance by Atlantic City
Electric Transition Funding LLC (ACE Funding) of transition bonds (Transition
Bonds). A customer surcharge is collected by ACE to fund principal
and interest payments on the Transition Bonds. The stranded costs are
amortized over the life of the Transition Bonds, which mature between 2010 and
2023. A return is received on these deferrals with the exception of
taxes.
184
PEPCO
HOLDINGS
Pension and OPEB
Costs: Represents the funded portion of Pepco Holdings’
defined benefit pension and other postretirement benefit plans that is probable
of recovery in rates under SFAS No. 71 by Pepco, DPL and ACE. There
is no return on these deferrals.
Deferred Energy Supply
Costs: The regulatory asset primarily represents deferred
costs associated with a net under-recovery of Default Electricity Supply costs
incurred by Pepco and DPL. The regulatory liability primarily
represents deferred costs associated with a net over-recovery by ACE connected
with the provision of Default Electricity Supply and other restructuring related
costs incurred by ACE. A return is generally received on these
deferrals other than the Default Electricity Supply deferrals which do not earn
a return.
Deferred Income
Taxes: Represents a receivable from Power Delivery’s customers
for tax benefits applicable to utility operations of Pepco, DPL, and ACE
previously flowed through before the companies were ordered to provide deferred
income taxes. As the temporary differences between the financial
statement and tax basis of assets reverse, the deferred recoverable balances are
reversed. There is no return on these deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of
debt extinguishment of Pepco, DPL and ACE for which recovery through regulated
utility rates is considered probable and, if approved, will be amortized to
interest expense during the authorized rate recovery period. A return
is received on these deferrals.
Unrecovered Purchased Power Contract
Costs: Represents deferred costs related to purchase power
contracts entered into by ACE. The amortization period began in July
1994 and will end in May 2014 and earns a return.
Deferred Other Postretirement
Benefit Costs: Represents the non-cash
portion of other postretirement benefit costs deferred by ACE during 1993
through 1997. This cost is being recovered over a 15-year period that
began on January 1, 1998. There is no return on this
deferral.
Phase In
Credits: Represents phase-in credits for participating
Maryland and Delaware residential and small commercial customers to mitigate the
immediate impact of significant rate increases due to energy costs in
2006. The deferral period for Delaware was May 1, 2006 to
January 1, 2008 with recovery to occur over a 17-month period beginning
January 2008. The Delaware deferral will be recovered from
participating customers on a straight-line basis. The deferral period
for Maryland was June 1, 2006 to June 1, 2007, with the recovery
occurring over an 18-month period beginning June 2007 and ending in
2008. There is no return on these deferrals.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
Deferred Income Taxes Due to
Customers:
Represents the portion of deferred income tax liabilities applicable to utility
operations of Pepco, DPL, and ACE that has not been reflected in current
customer rates for which future payment to customers is probable. As
temporary differences between the financial statement and tax basis of assets
reverse, deferred recoverable income taxes are amortized. There is no
return on these deferrals.
Federal and New Jersey Tax Benefits,
Related to Securitized Stranded Costs: Securitized stranded
costs include a portion of stranded costs attributable to the future tax benefit
expected to
185
PEPCO
HOLDINGS
be
realized when the higher tax basis of generating plants divested by ACE is
deducted for New Jersey state income tax purposes as well as the future benefit
to be realized through the reversal of federal excess deferred
taxes. To account for the possibility that these tax benefits may be
given to ACE’s regulated electricity delivery customers through lower rates in
the future, ACE established a regulatory liability. The regulatory
liability related to federal excess deferred taxes will remain until such time
as the Internal Revenue Service issues its final regulations with respect to
normalization of these federal excess deferred taxes. There is no
return on these deferrals.
Asset Removal Costs: The depreciation rates
for Pepco and DPL include a component for removal costs, as approved by the
relevant federal and state regulatory commissions. As such, Pepco and
DPL have recorded regulatory liabilities for their estimate of the difference
between incurred removal costs and the level of removal costs recovered through
depreciation rates.
Excess Depreciation
Reserve: The excess depreciation reserve was recorded as part
of an ACE New Jersey rate case settlement. This excess reserve is the
result of a change in depreciable lives and a change in depreciation technique
from remaining life to whole life. The excess is being amortized over
an 8.25 year period, which began in June 2005. There is no return on
these deferrals.
Gain from Sale of Divested
Assets: Represents (i) the balance of the net gain realized by
ACE from the sale in 2006 of its interests in the Keystone and Conemaugh
generating facilities and (ii) the balance of the net proceeds realized by ACE
from the sale in 2007 of the B.L. England generating facility and the
monetization of associated emission allowance credits. Both gains are
being returned to ACE’s ratepayers as a credit on their bills — the Keystone and
Conemaugh gain over a 33-month period that began during the October 2006 billing
period and the B.L. England and emission allowances proceeds over a 12-month
period that began during the June 2008 billing period. There is no
return on these deferrals.
Settlement Proceeds - Mirant
Bankruptcy Claims: In 2007, Pepco received $414 million of net
proceeds from settlement of a Mirant Corporation (Mirant) claim, plus interest
earned, which was designated to pay for future above-market capacity and energy
purchases under the Panda PPA. In 2008, Pepco transferred the Panda
PPA to Sempra Energy Trading LLC (Sempra) in a transaction in which Pepco made a
payment to Sempra and all further Pepco rights, obligations and liabilities
under the Panda PPA were terminated. The balance at December 31, 2008
reflects the funds remaining after the Sempra payment. Pepco filed
rate applications with the DCPSC and the MPSC in the fourth quarter of 2008 to
provide for the disposition of the remaining funds. See Note (16),
“Commitments and Contingencies — Proceeds from Settlement of Mirant Bankruptcy
Claims” for additional information. Currently there is no return on
these deferrals.
Other: Includes
miscellaneous regulatory liabilities such as the over-recovery of administrative
costs associated with Maryland, Delaware and District of Columbia
SOS. These regulatory liabilities generally do not receive a
return.
186
PEPCO
HOLDINGS
(8) LEASING
ACTIVITIES
Investment in Finance Leases
Held in Trust
As of December 31, 2008 and
December 31, 2007, Pepco Holdings had cross-border energy lease investments
of $1.3 billion and $1.4 billion, respectively, consisting of hydroelectric
generation and coal-fired electric generation facilities and natural gas
distribution networks located outside of the United States.
As further discussed in Note (2),
“Significant Accounting Policies — Changes in Accounting Estimates,” and Note
(16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease
Investments,” during the second quarter of 2008, PHI reassessed the
sustainability of its tax position and revised its assumptions regarding the
estimated timing of tax benefits generated from its cross-border energy lease
investments. Based on this reassessment, PHI for the quarter ended June 30,2008, recorded a reduction in its cross-border energy lease investments of $124
million. No further charges were considered necessary in the third
and fourth quarters of 2008.
The components of the cross-border
energy lease investments at December 31, 2008 (reflecting the effects of
recording this charge) and at December 31, 2007 are summarized
below:
Scheduled
lease payments, net of non-recourse debt
$
2,281
$
2,281
Less: Unearned
and deferred income
(946)
(897)
Investment
in finance leases held in trust
1,335
1,384
Less: Deferred
income taxes
(679)
(773)
Net
investment in finance leases held in trust
$
656
$
611
Income recognized from cross-border
energy lease investments was comprised of the following for the years ended
December 31, 2008, 2007 and 2006:
2008
2007
2006
(Millions
of dollars)
Pre-tax
earnings from PHI’s cross-border energy lease
investments
(included in “Other Revenue”)
$
75
$
76
$
88
Non-cash
charge to reduce equity value of
PHI’s
cross-border energy lease investments
(124)
-
-
Pre-tax
(loss) earnings from PHI’s cross-border
energy
lease investments after adjustment
(49)
76
88
Income
tax (benefit) expense
(12)
16
26
Net
(loss) income from PHI’s cross-border energy
lease
investments
$
(37)
$
60
$
62
187
PEPCO
HOLDINGS
Scheduled lease payments from the
cross-border energy lease investments are net of non-recourse
debt. Minimum lease payments receivable from the cross-border energy
lease investments for each of the years 2009 through 2013 and thereafter are
zero for 2009, $16 million for 2010, zero for 2011, 2012 and 2013, and $1,319
million thereafter.
Lease
Commitments
Pepco leases its consolidated control
center, which is an integrated energy management center used by Pepco to
centrally control the operation of its transmission and distribution
systems. This lease is accounted for as a capital lease and was
initially recorded at the present value of future lease payments, which totaled
$152 million. The lease requires semi-annual payments of $8 million
over a 25-year period beginning in December 1994 and provides for transfer of
ownership of the system to Pepco for $1 at the end of the lease
term. Under SFAS No. 71, the amortization of leased assets is
modified so that the total interest on the obligation and amortization of the
leased asset is equal to the rental expense allowed for rate-making
purposes. This lease has been treated as an operating lease for
rate-making purposes.
Capital lease assets recorded within
Property, Plant and Equipment at December 31, 2008 and 2007, in millions of
dollars, are comprised of the following:
The approximate annual commitments
under all capital leases are $15 million for each year 2009 through 2013, and
$92 million thereafter.
Rental expense for operating leases was
$69 million, $50 million, and $53 million for the years ended December 31,2008, 2007, and 2006, respectively.
Total future minimum operating lease
payments for Pepco Holdings as of December 31, 2008, are $56 million in
2009, $75 million in 2010, $44 million in 2011, $28 million in 2012, $19 million
in 2013 and $369 million after 2013.
188
PEPCO
HOLDINGS
(9) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
The non-operating and other property
amounts include balances for general plant, distribution and transmission plant
held for future use as well as other property held by non-utility
subsidiaries.
Pepco Holdings’ utility subsidiaries
use separate depreciation rates for each electric plant account. The rates vary
from jurisdiction to jurisdiction.
Asset
Sales
In the third quarter of 2006, ACE
completed the sale of its interest in the Keystone and Conemaugh generating
facilities for approximately $175 million (after giving effect to post-closing
adjustments). In the first quarter of 2007, ACE completed the sale of the B.L.
England generating facility for a price of $9 million. In February
2008, ACE received an additional $4 million in settlement of an arbitration
proceeding concerning the terms of the purchase agreement. See Note
(7), “Regulatory Assets and Regulatory Liabilities,” for treatment of gains from
these sales.
In
January 2008, DPL completed (i) the sale of its retail electric
distribution assets on the Eastern Shore of Virginia to A&N Electric
Cooperative for a purchase price of approximately $49 million, after closing
adjustments, and (ii) the sale of its wholesale electric transmission assets
located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative
for a purchase price of approximately $5 million, after closing
adjustments.
Jointly Owned
Plant
PHI’s Consolidated Balance Sheet
includes its proportionate share of assets and liabilities related to jointly
owned plant. PHI’s subsidiaries have ownership interests in
transmission facilities and other facilities in which various parties also have
ownership interests. PHI’s
189
PEPCO
HOLDINGS
proportionate
share of operating and maintenance expenses of the jointly owned plant is
included in the corresponding expenses in PHI’s Consolidated Statements of
Earnings. PHI is responsible for providing its share of financing for
the jointly owned facilities. Information with respect to PHI’s share
of jointly owned plant as of December 31, 2008 is shown below.
Jointly
Owned Plant
Ownership
Share
Plant
in
Service
Accumulated
Depreciation
(Millions
of dollars)
Transmission
Facilities
Various
$
36
$
24
Other
Facilities
Various
5
2
Total
$
41
$
26
Asset Retirement Obligations
(AROs)
A reconciliation of the balances of
PHI’s AROs is shown in the table below for the years ended December 31,2008 and 2007 (millions of dollars):
During the first quarter of 2006, ACE
recorded an asset retirement obligation of $60 million for the B.L. England
plant demolition and environmental remediation costs; the obligation was to be
amortized over a two-year period. In the first quarter of 2007, ACE
completed the sale of the B.L. England generating facilities and the asset
retirement obligation and asset retirement costs were reversed.
(10) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
Pension Benefits and
Other
Postretirement Benefits
Pepco Holdings sponsors the PHI
Retirement Plan, which covers substantially all employees of Pepco, DPL, ACE and
certain employees of other Pepco Holdings’ subsidiaries. Pepco
Holdings also provides supplemental retirement benefits to certain eligible
executive and key employees through nonqualified retirement plans.
Pepco Holdings provides certain
postretirement health care and life insurance benefits for eligible retired
employees. Most employees hired on January 1, 2005 or later will not
have company subsidized retiree medical coverage; however, they will be able to
purchase coverage at full cost through PHI.
Pepco Holdings accounts for the PHI
Retirement Plan and nonqualified retirement plans in accordance with
SFAS No. 87, “Employers’ Accounting for Pensions,” and its
postretirement
190
PEPCO
HOLDINGS
health
care and life insurance benefits for eligible employees in accordance with
SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other
Than Pensions.” In addition, on December 31, 2006, Pepco Holdings
implemented SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and
132 (R)” (SFAS No. 158), which requires that companies recognize a net liability
or asset to report the funded status of their defined benefit pension and other
postretirement benefit plans on the balance sheet, with an offset to accumulated
other comprehensive income in shareholders’ equity or a deferral in a regulatory
asset or liability if probable of recovery in rates under SFAS No. 71,
“Accounting For the Effects of Certain Types of Regulation.” SFAS
No.158 does not change how pension and other postretirement benefits expenses
are accounted for and reported in the consolidated statements of
earnings. PHI’s financial statement disclosures are prepared in
accordance with SFAS No. 132, “Employers’ Disclosures about Pensions
and Other Postretirement Benefits,” as revised and amended by SFAS No.
158. Refer to Note (2), “Significant Accounting Policies — Pension
and Other Postretirement Benefit Plans,” for additional
information.
All amounts in the following tables are
in millions of dollars.
At
December 31,
Pension
Benefits
Other
Postretirement
Benefits
Change
in Benefit Obligation
2008
2007
2008
2007
Benefit
obligation at beginning of year
$
1,701
$
1,715
$
620
$
611
Service
cost
36
36
7
7
Interest
cost
108
102
40
37
Amendments
15
4
-
-
Actuarial
(gain) loss
3
(7)
24
3
Benefits
paid
(110)
(149)
(38)
(38)
Benefit
obligation at end of year
$
1,753
$
1,701
$
653
$
620
Change
in Plan Assets
Fair
value of plan assets at beginning of year
$
1,631
$
1,633
$
234
$
206
Actual
return on plan assets
(403)
139
(56)
12
Company
contributions
5
8
52
54
Benefits
paid
(110)
(149)
(38)
(38)
Fair
value of plan assets at end of year
$
1,123
$
1,631
$
192
$
234
Funded
Status at end of year
(plan
assets less plan obligations)
$
(630)
$
(70)
$
$(461)
$
(386)
191
PEPCO
HOLDINGS
The following table provides the
amounts recognized in PHI’s Consolidated Balance Sheets as of December 31, 2008,
in compliance with SFAS No. 158:
Pension
Benefits
Other
Postretirement
Benefits
2008
2007
2008
2007
Regulatory
asset
$
726
$
203
$
218
$
131
Current
liabilities
(4)
(4)
-
-
Pension
benefit obligation
(626)
(66)
-
-
Other
postretirement benefit obligations
-
-
(461)
(385)
Deferred
income tax
6
5
-
-
Accumulated
other comprehensive income,
net
of tax
10
8
-
-
Net
amount recognized
$
112
$
146
$
(243)
$
(254)
Amounts
included in accumulated other comprehensive income (pre-tax) and regulatory
assets at December 31, 2008 in compliance with SFAS No. 158 consist
of:
Pension
Benefits
Other
Postretirement
Benefits
2008
2007
2008
2007
Unrecognized
net actuarial loss
$
742
$
215
$
241
$
159
Unamortized
prior service cost (credit)
-
-
(26)
(31)
Unamortized
transition liability
-
-
3
3
$
742
$
215
$
218
$
131
Accumulated
other comprehensive income
($10
million, and $8 million net of tax)
16
12
-
-
Regulatory
assets
726
203
218
131
$
742
$
215
$
218
$
131
The table below provides the components
of net periodic benefit costs recognized for the years ended December
31.
Pension
Benefits
Other
Postretirement
Benefits
2008
2007
2006
2008
2007
2006
Service
cost
$36
$ 36
$ 41
$ 7
$ 7
$ 8
Interest
cost
108
102
97
40
37
35
Expected
return on plan assets
(130)
(130)
(130)
(16)
(14)
(11)
Amortization
of prior service cost
-
1
1
(4)
(4)
(4)
Amortization
of net loss
10
9
17
13
11
14
Recognition
of Benefit Contract
-
4
-
-
2
-
Curtailment/Settlement
(Gain)/Loss
-
3
-
-
-
-
Net
periodic benefit cost
$24
$ 25
$ 26
$40
$39
$ 42
The table below provides the split of
the combined pension and other postretirement net periodic benefit costs between
subsidiaries:
192
PEPCO
HOLDINGS
2008
2007
2006
Pepco
$
24
$
22
$
32
DPL
3
4
1
ACE
12
11
14
Other
subsidiaries
25
27
21
Total
$
64
$
64
$
68
The following weighted average
assumptions were used to determine the benefit obligations at December
31:
Pension
Benefits
Other
Postretirement
Benefits
2008
2007
2008
2007
Discount
rate
6.50%
6.25%
6.50%
6.25%
Rate
of compensation increase
5.00%
4.50%
5.00%
4.50%
Health
care cost trend rate assumed for current year
-
-
8.50%
8.00%
Rate
to which the cost trend rate is assumed to decline
(the
ultimate trend rate)
-
-
5.00%
5.00%
Year
that the rate reaches the ultimate trend rate
-
-
2015
2010
Assumed
health care cost trend rates may have a significant effect on the amounts
reported for the health care plans. A one-percentage-point change in assumed
health care cost trend rates would have the following effects (millions of
dollars):
1-Percentage-
Point
Increase
1-Percentage-
Point
Decrease
Increase
(decrease) on total service and interest cost
$ 2
$ (2)
Increase
(decrease) on postretirement benefit obligation
$36
$(31)
The following weighted average
assumptions were used to determine the net periodic benefit cost for the years
ended December 31:
Pension
Benefits
Other
Postretirement
Benefits
2008
2007
2006
2008
2007
2006
Discount
rate
6.25%
6.00%
5.625%
6.25%
6.00%
5.625%
Expected
long-term return on plan assets
8.25%
8.25%
8.50%
8.25%
8.25%
8.50%
Rate
of compensation increase
5.00%
4.50%
4.50%
5.00%
4.50%
4.50%
The
discount rate is developed using a cash flow matched bond portfolio approach to
value SFAS No. 87 and SFAS No. 106 liabilities. A hypothetical bond portfolio is
created comprised of high quality fixed income securities with cash flows and
maturities that mirror the expected benefit payments to be made under the
plans.
In selecting an expected rate of return
on plan assets, PHI considers actual historical returns, economic forecasts and
the judgment of its investment consultants on expected long-term performance for
the types of investments held by the plan. The plan assets consist of equity,
fixed income investments, real estate and private equity and, when viewed over a
long-term horizon, are expected to yield a return on assets of
8.25%.
193
PEPCO
HOLDINGS
In 2008, PHI and its actuaries
conducted an experience study, a periodic analysis of plan experience against
actuarial assumptions. The study reviewed withdrawal, retirement and
salary increase assumptions. As a result of the study, assumed
retirement rates were changed and the age-related salary scale assumption was
increased from an average over an employee’s career of 4.50% to
5.00%.
In addition, for the 2008 Other
Postretirement Benefit Plan valuation, the medical trend rate was changed to
8.5% declining .5% per year to 5% in 2015 and later, from the 2007 valuation
assumption for 2008 of 7% declining 1% per year to 5% in 2010 and
later.
Plan
Assets
The PHI Retirement Plan weighted
average asset allocations at December 31, 2008, and 2007, by asset category
are as follows:
Asset
Category
Plan
Assets
at
December 31,
Target
Plan
Asset
Allocation
Minimum/
Maximum
2008
2007
Equity
securities
50%
60%
60%
55%
- 65%
Debt
securities
41%
33%
30%
30%
- 50%
Other
9%
7%
10%
0%
- 10%
Total
100%
100%
100%
Pepco Holdings’ other postretirement
plan weighted average asset allocations at December 31, 2008, and 2007, by
asset category are as follows:
Asset
Category
Plan
Assets
at
December 31,
Target
Plan
Asset
Allocation
Minimum/
Maximum
2008
2007
Equity
securities
56%
62%
60%
55%
- 65%
Debt
securities
37%
34%
35%
20%
- 50%
Cash
7%
4%
5%
0%
- 10%
Total
100%
100%
100%
In developing an asset allocation
policy for the PHI Retirement Plan and other postretirement plan, PHI examined
projections of asset returns and volatility over a long-term
horizon. In connection with this analysis, PHI examined the
risk/return tradeoffs of alternative asset classes and asset mixes given
long-term historical relationships, as well as prospective capital market
returns. PHI also conducted an asset/liability study to match
projected asset growth with projected liability growth to determine whether
there is sufficient liquidity for projected benefit payments. By
incorporating the results of these analyses with an assessment of its risk
posture, and taking into account industry practices, PHI developed its asset mix
guidelines. Under these guidelines, PHI diversifies assets in order
to protect against large investment losses and to reduce the probability of
excessive performance volatility while maximizing return at an acceptable risk
level. Diversification of assets is implemented by allocating monies to various
asset classes and investment styles within asset classes, and by retaining
investment management firm(s) with complementary investment philosophies, styles
and approaches. Based on the assessment of demographics,
actuarial/funding, and business and financial characteristics, PHI believes that
its risk posture is slightly below average relative to
194
PEPCO
HOLDINGS
other
pension plans. Consequently, Pepco Holdings believes that a slightly
below average equity exposure (i.e., a target equity asset allocation of 60%) is
appropriate for the PHI Retirement Plan and the other postretirement
plan.
On a
periodic basis, Pepco Holdings reviews its asset mix and rebalances assets back
to the target allocation over a reasonable period of time. During 2008, the
volatility in the stock market made it challenging to maintain the target asset
allocation. PHI expects to return to its target asset allocation during 2009
through a combination of contributions to the plan and payment of monthly
benefits.
No Pepco Holdings common stock is
included in pension or postretirement program assets.
Cash
Flows
Contributions
- PHI Retirement Plan
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) and that is
at least equal to the funding target as defined under the Pension Protection Act
of 2006. As of the January 1, 2008 valuation, the PHI Retirement
Plan satisfied the minimum funding requirements of the Employee Retirement
Income Security Act of 1974 (ERISA) without requiring any additional funding. In
2008 and 2007, no contributions were made to the PHI Retirement
Plan.
At
December 31, 2008, PHI’s Plan assets were approximately $1.1 billion and
the ABO was approximately $1.6 billion. At December 31, 2007, PHI’s Plan
assets were approximately $1.6 billion and the ABO was approximately $1.6
billion. Although PHI projects there will be no minimum funding requirement
under the Pension Protection Act guidelines in 2009, PHI expects to make
discretionary tax-deductible contribution of approximately $300 million to bring
its plan assets to at least the funding target level for 2009 under the Pension
Protection Act.
Contributions
- Other Postretirement Benefits
In 2008 and 2007, Pepco contributed $9
million and $10 million, respectively, DPL contributed $9 million and $8
million, respectively, and ACE contributed $7 million and $7 million,
respectively, to the other postretirement benefit plan. In 2008 and
2007, contributions of $14 million and $13 million, respectively, were made by
other PHI subsidiaries. Assuming no changes to the other
postretirement benefit pension plan assumptions, PHI expects similar amounts to
be contributed in 2009.
Expected
Benefit Payments
Estimated future benefit payments to
participants in PHI’s pension and postretirement welfare benefit plans, which
reflect expected future service as appropriate, as of December 31, 2008 are as
follows (millions of dollars):
195
PEPCO
HOLDINGS
Years
Pension Benefits
Other Postretirement
Benefits
2009
$114
$ 41
2010
115
44
2011
119
47
2012
123
48
2013
121
50
2014
through 2018
632
262
Medicare Prescription Drug
Improvement and Modernization Act of 2003
On December 8, 2003, the Medicare
Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act)
became effective. The Medicare Act introduced a prescription drug
benefit under Medicare (Medicare Part D), as well as a federal subsidy to
sponsors of retiree health care benefits plans that provide a benefit that is at
least actuarially equivalent to Medicare Part D. Pepco Holdings
sponsors postretirement health care plans that provide prescription drug
benefits that PHI plan actuaries have determined are actuarially equivalent to
Medicare Part D. At December 31, 2008, the estimated reduction
in accumulated postretirement benefit obligation is $30 million. In 2008 and
2007, Pepco Holdings received $2 million in Federal Medicare prescription drug
subsidies.
Pepco Holdings Retirement
Savings Plan
Pepco Holdings has a defined
contribution retirement savings plan. Participation in the plan is
voluntary. All participants are 100% vested and have a nonforfeitable
interest in their own contributions and in the Pepco Holdings company matching
contributions, including any earnings or losses thereon. Pepco
Holdings’ matching contributions were $12 million, $11 million, and $11 million
for the years ended December 31, 2008, 2007, and 2006,
respectively.
196
PEPCO
HOLDINGS
(11) DEBT
LONG-TERM
DEBT
The
components of long-term debt are shown below.
At December 31,
Interest
Rate
Maturity
2008
2007
(Millions of dollars)
First
Mortgage Bonds
Pepco:
6.50%
2008
$
-
$
78
5.875%
2008
-
50
5.75% (a)
2010
16
16
4.95% (a)(b)
2013
200
200
4.65% (a)(b)
2014
175
175
Variable
(a)(b)(e)
2022
-
110
5.375%
(a)
2024
38
38
5.75% (a)(b)
2034
100
100
5.40%
(a)(b)
2035
175
175
6.50%
(a)(b)
2037
500
250
7.90%
2038
250
-
ACE:
6.71%
- 6.81%
2008
-
50
7.25%
- 7.63%
2010 - 2014
8
8
6.63%
2013
69
69
7.68%
2015 - 2016
17
17
7.75%
2018
250
-
6.80% (a)
2021
39
39
5.60% (a)
2025
4
4
Variable
(a)(b)(e)
2029
-
55
5.80% (a)(b)
2034
120
120
5.80% (a)(b)
2036
105
105
DPL:
6.40%
2013
250
-
Amortizing
First Mortgage Bonds
DPL:
6.95%
2008
-
4
Total
First Mortgage Bonds
$
2,316
$
1,663
Unsecured
Tax-Exempt Bonds
DPL:
5.20%
2019
$
31
$
31
3.15%
(e) (f)
2023
-
18
5.50%
(c)
2025
15
15
4.90%
(d)
2026
35
35
5.65%
(c)
2028
16
16
Variable
(e)
2030 — 2038
-
94
Total
Unsecured Tax-Exempt Bonds
$
97
$
209
(a)
Represents
a series of First Mortgage Bonds issued by the indicated company as
collateral for an outstanding series of senior notes issued by the company
or tax-exempt bonds issued for the benefit of the company. The
maturity date, optional and mandatory prepayment provisions, if any,
interest rate, and interest payment dates on each series of senior notes
or the obligations in respect of the tax-exempt bonds are identical to the
terms of the corresponding series of collateral First Mortgage
Bonds. Payments of principal and interest on a series of senior
notes or the company’s obligations in respect of the tax-exempt bonds
satisfy the corresponding payment obligations on the related series of
collateral First Mortgage Bonds. Because each series of senior
notes and tax-exempt bonds and the corresponding series of collateral
First Mortgage Bonds securing that series of senior notes or tax-exempt
bonds effectively represents a single financial obligation, the senior
notes and the tax-exempt bonds are not separately shown on the
table.
(b)
Represents
a series of First Mortgage Bonds issued by the indicated company as
collateral for an outstanding series of senior notes as described in
footnote (a) above that will, at such time as there are no First Mortgage
Bonds of the issuing company outstanding (other than collateral First
Mortgage Bonds securing payment of senior notes), cease to secure the
corresponding series of senior notes and will be
cancelled.
(c)
The
bonds are subject to mandatory tender on July 1,2010.
(d)
The
bonds are subject to mandatory tender on May 1,2011.
(e)
Represents
tax exempt bonds issued by municipal authorities for the benefit of the
company that were purchased at par by the company in 2008. The
obligations of the company with respect to the bonds are considered to be
extinguished for accounting purposes. The company currently
intends to hold the bonds until such time as they can be resold to the
public.
(f)
The
bonds were subject to mandatory tender on August 1,2008.
NOTE: Schedule
is continued on next page.
197
PEPCO
HOLDINGS
At December 31,
Interest
Rate
Maturity
2008
2007
(Millions
of dollars)
Medium-Term
Notes (unsecured)
Pepco:
6.25%
2009
$
50
$
50
DPL:
7.56%
- 7.58%
2017
14
14
6.81%
2018
4
4
7.61%
2019
12
12
7.72%
2027
10
10
Total
Medium-Term Notes (unsecured)
$
90
$
90
Recourse
Debt
PCI:
6.59% - 6.69%
2014
$
11
$
11
7.40%
(a)
2008
-
92
Total
Recourse Debt
$
11
$
103
Notes
(secured)
Pepco
Energy Services:
7.85%
2017
$
10
$
10
Notes
(unsecured)
PHI:
Variable
2010
$
250
$
250
4.00%
2010
200
200
6.45%
2012
750
750
5.90%
2016
200
200
6.125%
2017
250
250
6.00%
2019
200
200
7.45%
2032
250
250
DPL:
5.00%
2014
100
100
5.00%
2015
100
100
5.22%
2016
100
100
Total
Notes (unsecured)
$
2,400
$
2,400
Total
Long-Term Debt
$
4,924
$
4,475
Net
unamortized discount
(15)
(7)
Current
maturities of long-term debt
(50)
(293)
Total
Net Long-Term Debt
$
4,859
$
4,175
Transition
Bonds Issued by ACE Funding
2.89%
2010
$
-
$
13
2.89%
2011
5
15
4.21%
2013
57
66
4.46%
2016
52
52
4.91%
2017
118
118
5.05%
2020
54
54
5.55%
2023
147
147
Total
$
433
$
465
Net
unamortized discount
-
-
Current
maturities of long-term debt
(32)
(31)
Total
Transition Bonds issued by ACE Funding
$
401
$
434
(a)
Debt
issued at a fixed rate of 8.24%. The debt was swapped into
variable rate debt at the time of
issuance.
NOTE: Schedule
is continued on next page.
198
PEPCO
HOLDINGS
The outstanding First Mortgage Bonds
issued by each of Pepco, DPL and ACE are subject to a lien on substantially all
of the issuing company’s property, plant and equipment.
ACE Funding was established in 2001
solely for the purpose of securitizing authorized portions of ACE’s recoverable
stranded costs through the issuance and sale of Transition Bonds. The
proceeds of the sale of each series of Transition Bonds have been transferred to
ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a
non-bypassable transition bond charge from ACE customers pursuant to bondable
stranded costs rate orders issued by the NJBPU in an amount sufficient to fund
the principal and interest payments on the Transition Bonds and related taxes,
expenses and fees (Bondable Transition Property). The assets of ACE
Funding, including the Bondable Transition Property, and the Transition Bond
charges collected from ACE’s customers, are not available to creditors of
ACE. The holders of Transition Bonds have recourse only to the assets
of ACE Funding.
The aggregate amounts of maturities for
long-term debt and Transition Bonds outstanding at December 31, 2008, are $82
million in 2009, $532 million in 2010, $70 million in 2011, $787 million in
2012, $558 million in 2013, and $3,328 million thereafter.
PHI’s long-term debt is subject to
certain covenants. PHI and its subsidiaries are in compliance with
all requirements.
LONG-TERM
PROJECT FUNDING
As of December 31, 2008 and 2007, Pepco
Energy Services had outstanding total long-term project funding (including
current maturities) of $21 million and $29 million, respectively, related to
energy savings contracts performed by Pepco Energy Services. The
aggregate amounts of maturities for the project funding debt outstanding at
December 31, 2008, are $2 million for each year 2009 through 2013, and $11
million thereafter.
SHORT-TERM
DEBT
Pepco Holdings and its regulated
utility subsidiaries have traditionally used a number of sources to fulfill
short-term funding needs, such as commercial paper, short-term notes, and bank
lines of credit. Proceeds from short-term borrowings are used
primarily to meet working capital needs, but may also be used to temporarily
fund long-term capital requirements. A detail of the components of
Pepco Holdings’ short-term debt at December 31, 2008 and 2007 is as
follows.
2008
2007
(Millions
of dollars)
Commercial
paper
$ -
$137
Variable
rate demand bonds
118
152
Bonds
held under Standby Bond Purchase Agreement
22
-
Bank
Loans
175
-
Credit
Facility Loans
150
-
Total
$465
$289
199
PEPCO
HOLDINGS
Commercial
Paper
Pepco Holdings maintains an ongoing
commercial paper program of up to $875 million. Pepco, DPL, and ACE
have ongoing commercial paper programs of up to $500 million, $500 million,
and $250 million, respectively. The commercial paper programs of
PHI, Pepco, DPL and ACE are backed by $1.9 billion in credit facilities, which
are described under the heading “Credit Facilities” below.
Pepco Holdings, Pepco, DPL and ACE had
no commercial paper outstanding at December 31, 2008. The
weighted average interest rate for Pepco Holdings, Pepco, DPL and ACE commercial
paper issued during 2008 was 3.18%, 3.45%, 3.88% and 3.12%
respectively. The weighted average maturity for Pepco Holdings,
Pepco, DPL and ACE was three, two, five and four days respectively for all
commercial paper issued during 2008.
Variable Rate Demand
Bonds
Variable
Rate Demand Bonds (VRDB) are subject to repayment on the demand of the holders
and for this reason are accounted for as short-term debt in accordance with
GAAP. However, bonds submitted for purchase are remarketed by a
remarketing agent on a best efforts basis. PHI expects that the bonds
submitted for purchase will continue to be remarketed successfully due to the
credit worthiness of the issuing company and because the remarketing resets the
interest rate to the then-current market rate. The issuing company
also may utilize one of the fixed rate/fixed term conversion options of the
bonds to establish a maturity which corresponds to the date of final maturity of
the bonds. On this basis, PHI views VRDBs as a source of long-term
financing. The VRDBs outstanding at December 31, 2008 mature as
follows: 2009 to 2010 ($3 million), 2014 to 2017 ($49 million), 2024 ($24
million) and 2028 to 2031 ($64 million). The weighted average
interest rate for VRDB was 3.10% during 2008 and 3.79% during
2007. Of the $118 million in VRDB, $72 million are secured by First
Mortgage Bonds issued by DPL, the issuer of the VRDB.
Bank
Loans
In March
2008, DPL obtained a $150 million unsecured term loan that matures in July
2009. Interest on the loan is calculated at a variable
rate.
In May
2008, Pepco obtained a $25 million bank loan that matures on April 30,2009. Interest on the loan is calculated at a variable
rate.
Credit
Facilities
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under this primary credit
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is, at the borrowing company’s election, (i) the greater of the
prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the
prevailing Eurodollar rate, plus a margin that varies according to the credit
rating of the
200
PEPCO
HOLDINGS
borrower. The
facility also includes a “swingline loan sub-facility,” pursuant to which each
company may make same day borrowings in an aggregate amount not to exceed $150
million. Any swingline loan must be repaid by the borrower within
seven days of receipt thereof. All indebtedness incurred under the
facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties must be true, and the borrower must be in
compliance with specified covenants, including (i) the requirement that
each borrowing company maintain a ratio of total indebtedness to total
capitalization of 65% or less, computed in accordance with the terms of the
credit agreement, which calculation excludes from the definition of total
indebtedness certain trust preferred securities and deferrable interest
subordinated debt (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than certain sales
and dispositions, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other than permitted
liens. The absence of a material adverse change in the borrower’s
business, property, and results of operations or financial condition is not a
condition to the availability of credit under the facility. The
facility does not include any rating triggers.
In
November 2008, PHI entered into a second credit facility in the amount of $400
million with a syndicate of nine lenders. Under the facility, PHI may
obtain revolving loans and swingline loans over the term of the facility, which
expires on November 6, 2009. The facility does not provide for the
issuance of letters of credit. All indebtedness incurred under the
facility is unsecured. The interest rate payable on funds borrowed
under the facility is, at PHI’s election, based on either (a) the prevailing
Eurodollar rate or (b) the highest of (i) the prevailing prime rate, (ii) the
federal funds effective rate plus 0.5% or (iii) the one-month Eurodollar rate
plus 1.0%, plus a margin that varies according to the credit rating of
PHI. Under the swingline loan sub-facility, PHI may obtain loans for
up to seven days in an aggregate principal amount which does not exceed 10% of
the aggregate borrowing limit under the facility. In order to obtain
loans under the facility, PHI must be in compliance with the same covenants and
conditions that it is required to satisfy for utilization of the primary credit
facility. The absence of a material adverse change in PHI’s business,
property, and results of operations or financial condition is not a condition to
the availability of credit under the facility. The facility does not
include any ratings triggers.
Typically,
PHI and its utility subsidiaries issue commercial paper if required to meet
their short-term working capital requirements. Given the recent lack
of liquidity in the commercial paper markets, the companies have borrowed under
the primary credit facility to maintain sufficient cash on hand to meet daily
short-term operating needs. As of December 31, 2008, PHI had an
outstanding loan of $50 million and Pepco had an outstanding loan of $100
million under this facility. In January 2009, PHI borrowed an additional $150
million under the facility.
201
PEPCO
HOLDINGS
(12) INCOME
TAXES
PHI and
the majority of its subsidiaries file a consolidated federal income tax
return. Federal income taxes are allocated among PHI and the
subsidiaries included in its consolidated group pursuant to a written tax
sharing agreement that was approved by the SEC in connection with the
establishment of PHI as a holding company as part of Pepco’s acquisition of
Conectiv on August 1, 2002. Under this tax sharing agreement,
PHI’s consolidated federal income tax liability is allocated based upon PHI’s
and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income
taxes, reconciliation of consolidated income tax expense, and components of
consolidated deferred tax liabilities (assets) are shown below.
During
2008, Pepco Holdings completed an analysis of its current and deferred income
tax accounts and, as a result, recorded an $8 million net credit to income tax
expense in 2008, which is primarily included in “Deferred tax adjustments” in
the reconciliation provided above.
202
PEPCO
HOLDINGS
In
conjunction with the analysis, Pepco Holdings also identified a $1 million
adjustment of its current and deferred income tax accounts that related to
pre-acquisition tax contingencies associated with the Conectiv acquisition in
2002, which was recorded as an increase in goodwill. Also identified
as part of the analysis were new uncertain tax positions under FIN 48 (primarily
representing overpayments of income taxes in previously filed tax returns) that
resulted in the recording of after-tax net interest income of $4 million, which
is included as a reduction of income tax expense.
In
addition, during 2008 Pepco Holdings recorded after-tax net interest income of
$18 million under FIN 48 primarily related to the reversal of previously accrued
interest payable resulting from tentative and final settlements, respectively,
on the Mixed Service Cost and like-kind exchange issues with the IRS and a claim
made with the IRS related to the tax reporting for fuel over- and
under-recoveries. This amount was offset by $7 million in after-tax
interest expense related to the change in assumptions regarding the estimated
timing of the tax benefits on cross-border energy lease
investments.
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant
Accounting Policies,” PHI adopted FIN 48 effective January 1,2007. Upon adoption, PHI recorded the cumulative effect of the change
in accounting principle of $7 million as a decrease in retained
earnings. Also upon adoption, PHI had $187 million of unrecognized
tax benefits and $24 million of related accrued interest.
Reconciliation
of Beginning and Ending Balances of Unrecognized Tax Benefits
2008
2007
Beginning
balance as of January 1,
$
275
$
187
Tax
positions related to current year:
Additions
2
37
Reductions
-
(1)
Tax
positions related to prior years:
Additions
196
112
Reductions
(209)
(13)
Settlements
(9)
(47)
Ending
balance as of December 31,
$
255
$
275
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits related to tax positions that have been taken or are expected
to be taken in tax returns that are not recognized in the financial statements
because, in accordance with FIN 48, management has either measured the tax
benefit at an amount less than the benefit claimed or expected to be claimed, or
has concluded that it is not more likely than not that the tax position will be
ultimately sustained.
For the majority of these tax
positions, the ultimate deductibility is highly certain, but there is
uncertainty about the timing of such deductibility. Unrecognized tax
benefits at December 31, 2008, included $18 million that, if recognized,
would lower the effective tax rate.
203
PEPCO
HOLDINGS
Interest and Penalties
PHI recognizes interest and penalties
relating to its uncertain tax positions as an element of income tax
expense. For the years ended December 31, 2008 and 2007, PHI
recognized $25 million of interest income before tax ($15 million after-tax) and
$4 million of interest expense before tax ($2 million after-tax), respectively,
as a component of income tax expense. As of December 31, 2008 and
2007, PHI had $16 million and $31 million, respectively, of accrued interest
payable related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax
Benefits
It is reasonably possible that the
amount of the unrecognized tax benefit with respect to some of PHI’s uncertain
tax positions will significantly increase or decrease within the next
12 months. The possible settlement of the cross-border energy lease
investments issue, the final resolution of the Mixed Service Cost issue, or
other federal or state audits could impact the balances
significantly. At this time, other than the Mixed Service Cost issue,
an estimate of the range of reasonably possible outcomes cannot be
determined. The unrecognized benefit related to the Mixed Service
Cost issue could decrease by $55 million within the next 12 months
upon the final resolution of the tentative settlement with the IRS and the
obligation becomes certain. See Note (16), “Commitments and
Contingencies,” for additional information.
Tax Years Open to
Examination
PHI and the majority of its
subsidiaries file a consolidated federal income tax return. PHI’s
federal income tax liabilities for Pepco legacy companies for all years through
2000, and for Conectiv legacy companies for all years through 1999, have been
determined by the IRS, subject to adjustment to the extent of any net operating
loss or other loss or credit carrybacks from subsequent years. The
open tax years for the significant states where PHI files state income tax
returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and
Virginia) are the same as noted above.
204
PEPCO
HOLDINGS
Components of Consolidated
Deferred Tax Liabilities (Assets)
Depreciation
and other basis differences related to plant and equipment
$
1,545
$
1,408
Goodwill
and fair value adjustments
(104)
(108)
Deferred
electric service and electric restructuring liabilities
189
195
Finance
and operating leases
677
734
State
net operating loss
(43)
(46)
Valuation
allowance on state net operating loss
35
36
Pension
and other postretirement benefits
141
36
Deferred
taxes on amounts to be collected through future rates
42
33
Other
(243)
(207)
Total
Deferred Tax Liabilities, Net
2,239
2,081
Deferred
tax assets included in Other Current Assets
31
25
Deferred
tax liabilities included in Other Current Liabilities
(1)
(1)
Total
Consolidated Deferred Tax Liabilities, Net Non-Current
$
2,269
$
2,105
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement and tax basis of assets and
liabilities. The portion of the net deferred tax liability applicable to PHI’s
operations, which has not been reflected in current service rates, represents
income taxes recoverable through future rates, net and is recorded as a
regulatory asset on the balance sheet.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously earned on Pepco’s,
DPL’s and ACE’s property continues to be normalized over the remaining service
lives of the related assets.
Resolution of Certain
Internal Revenue Service Audit Matters
In 2006, PHI resolved certain, but not
all, tax matters that were raised in Internal Revenue Service audits related to
the 2001 and 2002 tax years. Adjustments recorded related to these
resolved tax matters resulted in a $6 million increase in net income ($3 million
for Power Delivery and $5 million for Other Non-Regulated, partially offset by
an unfavorable $2 million impact in Corp. & Other). To the extent
that the matters resolved related to tax contingencies from the Conectiv legacy
companies that existed at the August 2002 merger date, in accordance with
accounting rules, an additional adjustment of $9 million ($3 million related to
Power Delivery and $6 million related to Other Non-Regulated) was recorded in
Corp. & Other to eliminate the tax benefits recorded by Power Delivery and
Other Non-Regulated against the goodwill balance that resulted from the
merger. Also during 2006, the total favorable impact of $3 million
was recorded that resulted from changes in estimates related to prior year tax
liabilities subject to audit ($4 million for Power Delivery, partially offset by
an unfavorable $1 million for Corp. & Other).
205
PEPCO
HOLDINGS
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. The total amounts below include $347 million,
$348 million, and $333 million, for the years ended December 31, 2008,
2007, and 2006, respectively, related to the Power Delivery Business, which are
recoverable through rates.
2008
2007
2006
(Millions
of dollars)
Gross
Receipts/Delivery
$146
$146
$149
Property
67
64
63
County
Fuel and Energy
90
88
84
Environmental,
Use and Other
56
59
47
Total
$359
$357
$343
(13) MINORITY
INTEREST
The outstanding preferred stock issued
by subsidiaries of PHI as of December 31, 2008 and 2007 consisted of the
following series of serial preferred stock issued by ACE. The shares
of each of the series are redeemable solely at the option of the
issuer.
STOCK-BASED
COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER
SHARE OF COMMON STOCK
Stock-Based
Compensation
PHI maintains a Long-Term Incentive
Plan (LTIP), the objective of which is to increase shareholder value by
providing a long-term incentive to reward officers, key employees, and directors
of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco
Holdings’ common stock by such individuals. Any officer or key employee of Pepco
Holdings or its subsidiaries may be designated by the PHI board of directors as
a participant in the LTIP. Under the LTIP, awards to officers and key employees
may be in the form of restricted stock, stock options, performance units, stock
appreciation rights, and dividend equivalents. At the time of the adoption of
the LTIP, 10 million shares of common stock were reserved for issuance under the
LTIP over a period of 10 years commencing August 1, 2002.
Total stock-based compensation expense
recorded in the Consolidated Statements of Earnings for the years ended December31, 2008, 2007, and 2006 is $16 million, $4 million, and
206
PEPCO
HOLDINGS
$6
million, respectively. During 2008, PHI recorded a correction to its
prior-year stock based compensation expense. See discussion of the correction in
Note (2), “Significant Accounting Policies ¾
Reclassification.” For the years ended December 31, 2008, 2007, and
2006, $1 million in tax expense and $2 million and zero, respectively, in tax
benefits were recognized in relation to stock-based compensation costs of stock
awards. No compensation costs related to restricted stock grants were
capitalized for the years ended December 31, 2008, 2007 and 2006.
PHI recognizes compensation expense
related to performance restricted stock awards and time-restricted share awards
based on the fair value of the awards at date of grant. PHI estimated
the fair value of market condition awards for its 2005-2007 performance
restricted stock awards using a Monte Carlo simulation model, in a risk-neutral
framework, based on the following assumptions:
Performance
Period
2005-2007
Risk-free
interest rate (%)
3.37
Peer
volatilities (%)
15.5
- 60.1
Peer
correlations
0.15
- 0.72
Fair
value of restricted share
$26.92
Prior to
the acquisition of Conectiv by Pepco in 2002, each company had a long-term
incentive plan under which stock options were granted. At the time of the
acquisition, certain Conectiv options were exchanged on a 1 for 1.28205 basis
for Pepco Holdings stock options under the LTIP, resulting in the conversion of
590,198 Conectiv stock options into 756,660 Pepco Holdings stock options. At
December 31, 2008, 116,404 of these options remained outstanding, all of which
are exercisable at exercise prices of either $13.08 or $19.03.
At the
same time, all outstanding Pepco options were exchanged on a one-for-one basis
for Pepco Holdings stock options granted under the LTIP. At December 31, 2008,
258,500 of these options remained outstanding, all of which are exercisable. The
exercise prices of these options are $21.825, $22.4375, $22.57, $22.685,
$23.15625, $24.59 and $29.78125.
Stock option activity for the three
years ended December 31, 2008, 2007 and 2006 is summarized below. The
information presented in the table is for Pepco Holdings, including converted
Pepco and Conectiv options.
2008
2007
2006
Number
of
Options
Weighted
Average Price
Number
of
Options
Weighted
Average Price
Number
of
Options
Weighted
Average
Price
Beginning-of-year
balance
532,635
$
22.3443
1,130,724
$
22.5099
1,864,250
$
22.1944
Options
exercised
130,231
$
22.3512
591,089
$
22.6139
733,526
$
21.7081
Options
lapsed
27,500
$
23.3968
7,000
$
26.3259
-
$
-
End-of-year
balance
374,904
$
22.2647
532,635
$
22.3443
1,130,724
$
22.5099
Exercisable
at end of year
374,904
$
22.2647
532,635
$
22.3443
1,130,724
$
22.5099
All stock options have an expiration
date of ten years from the date of grant.
207
PEPCO
HOLDINGS
The aggregate intrinsic value of stock
options outstanding and exercisable at December 31, 2008, 2007, and 2006
was zero, $4 million, and $4 million, respectively.
The total intrinsic value of stock
options exercised during the years ended December 31, 2008, 2007, and 2006
was less than $1 million, $3 million, and $2 million,
respectively. For the years ended December 31, 2008, 2007, and 2006,
less than $1 million, $1 million, and $1 million, respectively, in tax benefits
were recognized in relation to stock-based compensation costs of stock
options.
As of December 31, 2008, an analysis of
options outstanding by exercise prices is as follows:
There were no options granted in 2008,
2007, or 2006.
The Performance Restricted Stock
Program and the Merger Integration Success Program have been established under
the LTIP. Under the Performance Restricted Stock Program, performance
criteria are selected and measured over a three-year period. The
target number of share award opportunities established in 2008, 2007 and 2006
under Pepco Holdings’ Performance Restricted Stock Program for performance
periods 2008-2010, 2007-2009, and 2006-2008 were 187,175, 200,885, and 218,108,
respectively. Additionally, beginning in 2006, time-restricted share
award opportunities with a requisite service period of three years were
established under the LTIP. The target number of share award
opportunities for these awards was 93,584 for the 2008-2010 time period, 100,430
for the 2007-2009 time period and 109,057 for the 2006-2008 time
period. The fair value per share on award date for the performance
restricted stock was $25.36 for the 2008-2010 award, $25.54 for the 2007-2009
award, and $23.28 for the 2006-2008 award. Depending on the extent to
which the performance criteria are satisfied, the executives are eligible to
earn shares of common stock and dividends accrued thereon over the vesting
period, under the Performance Restricted Stock Program ranging from 0% to 200%
of the target share award opportunities, inclusive of dividends
accrued. There were 454,632 awards earned with respect to the
2005-2007 share award opportunity.
Under the LTIP, non-employee directors
are entitled to a grant on May 1 of each year of a nonqualified stock
option for 1,000 shares of common stock. However, the Board of
Directors has determined that these grants will not be made.
In
connection with the acquisition of Conectiv by Pepco, 80,602 shares of Conectiv
performance accelerated restricted stock (PARS) were converted to 104,298 shares
of Pepco Holdings restricted stock vesting over periods ranging from 5 to 7
years from the original grant date. As of December 31, 2008,
87,507 converted shares had vested, 10,122 were forfeited and 6,669 shares
remain unvested. On January 2, 2009, all remaining shares vested at
an average market price of $17.635 per share.
208
PEPCO
HOLDINGS
In
September 2007, retention awards in the form of 9,015 shares of restricted stock
were granted to certain PHI executives, with vesting periods of two or three
years. The 2008 activity for non-vested share opportunities with
respect to PHI common stock (including Conectiv PARS converted to Pepco Holdings
restricted stock) is summarized below.
The total fair value of restricted
stock awards vested during the years ended December 31, 2008, 2007, and
2006 was $12 million, $10 million, and $2 million, respectively.
As of December 31, 2008, there was
approximately $8 million of unrecognized compensation cost (net of estimated
forfeitures) related to non-vested stock granted under the
plans. That cost is expected to be recognized over a weighted-average
period of approximately two years.
Dividend
Restrictions
PHI, on a stand-alone basis, generates
no operating income of its own. Accordingly, its ability to pay
dividends to its shareholders depends on dividends received from its
subsidiaries. In addition to their future financial performance, the ability of
PHI’s direct and indirect subsidiaries to pay dividends is subject to limits
imposed by: (i) state corporate and regulatory laws, which impose limitations on
the funds that can be used to pay dividends and, in the case of regulatory laws,
as applicable, may require the prior approval of the relevant utility regulatory
commissions before dividends can be paid; (ii) the prior rights of holders of
existing and future preferred stock, mortgage bonds and other long-term debt
issued by the subsidiaries, and any other restrictions imposed in connection
with the incurrence of liabilities; and (iii) certain provisions of ACE’s
charter that impose restrictions on payment of common stock dividends for the
benefit of preferred stockholders. Pepco and DPL have no shares of
preferred stock outstanding. Currently, the restriction in the ACE
charter does not limit its ability to pay dividends. Restricted net
assets related to PHI’s consolidated subsidiaries amounted to approximately $2.1
billion at December 31, 2008 and $1.8 billion at December 31,2007. PHI had no restricted retained earnings or restricted net
income at December 31, 2008 and 2007.
209
PEPCO
HOLDINGS
For the years ended December 31,2008, 2007 and 2006, Pepco Holdings recorded dividends from its subsidiaries as
follows:
Subsidiary
2008
2007
2006
(Millions
of dollars)
Pepco
$
89
$
86
$
99
DPL
52
39
15
ACE
46
50
109
Conectiv
Energy
-
50
-
$
187
$
225
$
223
Directors’ Deferred
Compensation
Under the Pepco Holdings’ Executive and
Director Deferred Compensation Plan, Pepco Holdings directors may elect to defer
all or part of their retainer or meeting fees that constitute normal
compensation. Deferred retainer or meeting fees can be invested in
phantom Pepco Holdings shares and receive accruals equal to the dividends paid
on the corresponding number of sharers of Pepco Holdings common
stock. The phantom share account balances are settled in
cash. The amount deferred and invested in phantom Pepco Holdings
shares in the years ended December 31, 2008, 2007 and 2006 was de
minimis.
Compensation recognized in respect of
dividends and increase in fair value in the years ended December 31, 2008,
2007 and 2006 was de minimis. The balance of deferred compensation
invested in phantom Pepco Holdings’ shares at December 31, 2008 and 2007
was $1 million and $2 million, respectively.
Calculations of Earnings per
Share of Common Stock
The numerator and denominator for basic
and diluted earnings per share of common stock calculations are shown
below.
Weighted
Average Shares Outstanding for Computation of
Basic
and Diluted Earnings Per Share of Common Stock (a)
204
194
191
Basic
earnings per share of common stock
$
1.47
$
1.72
$
1.30
Diluted
earnings per share of common stock
$
1.47
$
1.72
$
1.30
(a)
Approximately
1 million shares at December 31, 2006 related to options to purchase
common stock have been excluded from the calculation of diluted EPS as
they are considered to be
anti-dilutive.
210
PEPCO
HOLDINGS
Shareholder Dividend
Reinvestment Plan
PHI maintains a Shareholder Dividend
Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends
and both existing shareholders and new investors can make purchases of shares of
PHI common stock through the investment of not less than $25 each calendar month
nor more than $200,000 each calendar year. Shares of common stock purchased
through the DRP may be original issue shares or, at the election of PHI, shares
purchased in the open market. There were approximately 1 million
original issue shares sold under the DRP in 2008, 2007 and 2006.
Pepco Holdings Common Stock
Reserved and Unissued
The following table presents Pepco
Holdings’ common stock reserved and unissued at December 31, 2008:
Name
of Plan
Number
of
Shares
DRP
1,436,151
Conectiv
Incentive Compensation Plan
(a)
1,187,157
Potomac
Electric Power Company Long-Term Incentive Plan (a)
327,059
Pepco
Holdings Long-Term Incentive Plan
8,473,554
Pepco
Holdings Non-Management Directors Compensation Plan
488,713
Pepco
Holdings Retirement Savings Plan (b)
3,617,173
Total
15,529,807
(a)
No
further awards will be made under this
plan.
(b)
Effective
January 30, 2006, Pepco Holdings established the Retirement Savings Plan
which is an amalgam of, and a successor to, (i) the Potomac Electric Power
Company Savings Plan for Bargaining Unit Employees, (ii) the Potomac
Electric Power Company Retirement Savings Plan for Management Employees
(which resulted from the merger, effective January 1, 2005, of the
Potomac Electric Power Company Savings Plan for Non-Bargaining Unit,
Non-Exempt Employees and the Potomac Electric Power Company Savings Plan
for Exempt Employees), (iii) the Conectiv Savings and Investment Plan, and
(iv) the Atlantic City Electric 401(k) Savings and Investment Plan -
B.
(15)
FAIR VALUES
DISCLOSURES
Effective
January 1, 2008, PHI adopted SFAS No. 157, as discussed earlier in Note
(3), which established a framework for measuring fair value and expanded
disclosures about fair value measurements.
As defined in SFAS No. 157, fair value
is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date (exit price). PHI utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. Accordingly, PHI
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. PHI is able to classify fair
value balances based on the observability of those inputs. SFAS No.
157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value. The
211
PEPCO
HOLDINGS
hierarchy
gives the highest priority to unadjusted quoted prices in active markets for
identical assets or liabilities (level 1 measurement) and the lowest priority to
unobservable inputs (level 3 measurement). The three levels of the
fair value hierarchy defined by SFAS No. 157 are as follows:
Level 1 — Quoted prices are available
in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
Level 2 — Pricing inputs are other than
quoted prices in active markets included in level 1, which are either
directly or indirectly observable as of the reporting date. Level 2 includes
those financial instruments that are valued using broker quotes in liquid
markets, and other observable pricing data. Level 2 also includes
those financial instruments that are valued using internally developed
methodologies that have been corroborated by observable market data through
correlation or by other means. Significant assumptions are observable
in the marketplace throughout the full term of the instrument, can be derived
from observable data or are supported by observable levels at which transactions
are executed in the marketplace.
Level 3 — Pricing inputs include
significant inputs that are generally less observable than those from objective
sources. Level 3 includes those financial instruments that are valued
using models or other valuation methodologies. Level 3 instruments classified as
derivative liabilities are primarily natural gas options. Some non-standard
assumptions are used in their forward valuation to adjust for the pricing;
otherwise, most of the options follow NYMEX valuation. A few of the options have
no significant NYMEX components, and have to be priced using internal volatility
assumptions. Some of the options do not expire until December 2011. All of
the options are part of the natural gas hedging program approved by the Delaware
Public Service Commission.
Level 3
instruments classified as executive deferred compensation plan assets and
liabilities are life insurance policies that are valued using the cash surrender
value of the policies. Since these values do not represent a quoted price in an
active market they are considered Level 3.
The following table sets forth by level
within the fair value hierarchy PHI’s financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31,2008. As required by SFAS No. 157, financial assets and liabilities
are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. PHI’s assessment of the
significance of a particular input to the fair value measurement requires the
exercise of judgment, and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy
levels.
Gains
(realized and unrealized) included in earnings for the period above are
reported in Operating Revenue, Other Comprehensive Income, Fuel and
Purchased Energy Expense and Other Operation and Maintenance Expense as
follows:
Other
Comprehensive Income
Operating
Revenue
Fuel
and Purchased Energy Expense
Other
Operation and Maintenance Expense
Total
(losses) gains included in earnings for
the
period above
$
-
$
(3)
$
(14)
$
4
Change
in unrealized gains (losses) relating to
assets
still held at reporting date
$
2
$
-
$
(17)
$
4
213
PEPCO
HOLDINGS
The estimated fair values of Pepco
Holdings’ non-derivative financial instruments at December 31, 2008 and 2007 are
shown below.
The methods and assumptions described
below were used to estimate, at December 31, 2008 and 2007, the fair value of
each class of non-derivative financial instruments shown above for which it is
practicable to estimate a value.
The fair value of long-term debt issued
by PHI and its utility subsidiaries was based on actual trade prices at December31, 2008 and 2007, or bid prices obtained from brokers, if actual trade prices
were not available. Long-term debt includes recourse and non-recourse
debt issued by PCI. The fair value of this debt, including amounts
due within one year, was determined based on current rates offered to companies
with similar credit ratings in the same industry as PHI for debt with similar
remaining maturities. The fair values of all other Long-Term Debt and
Transition Bonds issued by ACE Funding, including amounts due within one year,
were derived based on current market prices, or for issues with no market price
available, were based on discounted cash flows using current rates for similar
issues with similar credit ratings, terms, and remaining
maturities.
The fair value of the Redeemable Serial
Preferred Stock, excluding amounts due within one year, was derived based on
quoted market prices or discounted cash flows using current rates of preferred
stock with similar terms.
The carrying amounts of all other
financial instruments in Pepco Holdings’ accompanying financial statements
approximate fair value.
(16) COMMITMENTS AND
CONTINGENCIES
REGULATORY
AND OTHER MATTERS
Proceeds
from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. As part of the sale,
Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco was obligated to purchase annually through 2021 from Panda under the Panda
PPA at the purchase price Pepco was obligated to pay to Panda. 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 settlement of Pepco’s claims against Mirant
arising from the 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 was obligated to pay Panda for the energy
and
214
PEPCO
HOLDINGS
capacity
exceeded the market price. In 2007, Pepco received as damages
$414 million in net proceeds from the sale of shares of Mirant common stock
issued to it by Mirant.
On September 5, 2008, Pepco
transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a
payment to Sempra, thereby terminating all further rights, obligations and
liabilities of Pepco under the Panda PPA. The use of the damages
received from Mirant to offset above-market costs of energy and capacity under
the Panda PPA and to make the payment to Sempra reduced the balance of proceeds
from the Mirant settlement to approximately $102 million as of December 31,2008.
In November 2008, Pepco filed with the
DCPSC and the MPSC proposals to share with customers the remaining balance of
proceeds from the Mirant settlement in accordance with divestiture sharing
formulas previously approved by the respective commissions. Under
Pepco’s proposals, District of Columbia and Maryland customers would receive a
total of approximately $25 million and $29 million,
respectively. On December 12, 2008, the DCPSC issued a Notice of
Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds,
including the bankruptcy settlement proceeds. The public comment
period for the proposed rules has expired without any comments being
submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the
Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed
a settlement agreement with the MPSC. The settlement, among other
things, provides that of the remaining balance of the Mirant settlement, Pepco
shall distribute $39 million to its Maryland customers through a one-time
billing credit. If the settlement is approved by the MPSC, Pepco
currently estimates that it will result in a pre-tax gain in the range of $15
million to $20 million, which will be recorded when the MPSC issues its final
order approving the settlement.
Pending the final disposition of these
funds, the remaining $102 million in proceeds from the Mirant settlement is
being accounted for as restricted cash and as a regulatory
liability.
Rate
Proceedings
In the most recent electric service
distribution base rate cases filed by Pepco in the District of Columbia and
Maryland and by DPL in Maryland, and in a natural gas distribution case filed by
DPL in Delaware, Pepco and DPL proposed the adoption of a BSA for retail
customers. As more fully discussed below, the implementation of a BSA
has been approved for both Pepco and DPL electric service in Maryland and
remains pending for Pepco in the District of Columbia. A method of
revenue decoupling similar to a BSA, referred to as a modified fixed variable
rate design (MFVRD), has been adopted for DPL in Delaware, which will be
implemented in the context of DPL’s next Delaware base rate case.
Under the BSA, customer delivery rates
are subject to adjustment (through a surcharge or credit mechanism), depending
on whether actual distribution revenue per customer exceeds or falls short of
the approved revenue-per-customer amount. The BSA increases rates if
actual distribution revenues fall below the level approved by the applicable
commission and decreases rates if actual distribution revenues are above the
approved level. The result is that, over time, the utility collects
its authorized revenues for distribution deliveries. As a
consequence, a BSA “decouples” revenue from unit sales consumption and ties the
growth in revenues to the growth in the number of customers. Some
advantages of the BSA are that it (i) eliminates revenue
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fluctuations
due to weather and changes in customer usage patterns and, therefore, provides
for more predictable utility distribution revenues that are better aligned with
costs, (ii) provides for more reliable fixed-cost recovery,
(iii) tends to stabilize customers’ delivery bills, and (iv) removes
any disincentives for the regulated utilities to promote energy efficiency
programs for their customers, because it breaks the link between overall sales
volumes and delivery revenues. The MVFRD adopted in Delaware relies
primarily upon a fixed customer charge (i.e., not tied to the customer’s
volumetric consumption) to recover the utility’s fixed costs, plus a reasonable
rate of return. Although different from the BSA, DPL believes that
the MFRVD can serve as an appropriate revenue decoupling mechanism.
Delaware
On August 29, 2008, DPL submitted
its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting a 14.8% increase in
the level of GCR. On September 16, 2008, the DPSC issued an
initial order approving the requested increase, which became effective on
November 1, 2008, subject to refund pending final DPSC approval after
evidentiary hearings.
On January 26, 2009, DPL submitted
to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of
GCR. On February 5, 2009, the DPSC issued an initial order
approving the requested decrease, to become effective on March 1, 2009,
subject to refund pending final DPSC approval after evidentiary
hearings.
District of Columbia
In December 2006, Pepco submitted
an application to the DCPSC to increase electric distribution base rates,
including a proposed BSA. In January 2008, the DCPSC approved,
effective February 20, 2008, a revenue requirement increase of
approximately $28 million, based on an authorized return on rate base of
7.96%, including a 10% return on equity (ROE). This increase did not
include a BSA mechanism. While finding a BSA to be an appropriate
ratemaking concept, the DCPSC cited potential statutory problems in its
authority to implement the BSA. In February 2008, the DCPSC
established a Phase II proceeding to consider these implementation
issues. In August 2008, the DCPSC issued an order concluding that it
has the necessary statutory authority to implement the BSA proposal and that
further evidentiary proceedings are warranted to determine whether the BSA is
just and reasonable. On January 2, 2009, the DCPSC issued an order
designating the issues and establishing a procedural schedule for the BSA
proceeding. Hearings are scheduled for the second quarter of
2009.
In June 2008, the District of Columbia
Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC,
filed with the DCPSC a motion for reconsideration of the January 2008 order
granting Pepco’s rate increase, which was denied by the DCPSC. In
August 2008, the DC OPC filed with the District of Columbia Court of Appeals a
petition for review of the DCPSC order denying its motion for
reconsideration. The District of Columbia Court of Appeals granted
the petition; briefs have been filed by the parties and oral argument is
scheduled for March 2009.
Maryland
In July 2007, the MPSC issued
orders in the electric service distribution rate cases filed by DPL and Pepco,
each of which included approval of a BSA. The DPL order approved
an
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annual
increase in distribution rates of approximately $15 million (including a
decrease in annual depreciation expense of approximately
$1 million). The Pepco order approved an annual increase in
distribution rates of approximately $11 million (including a decrease in
annual depreciation expense of approximately $31 million). In
each case, the approved distribution rate reflects an ROE of 10%. The
rate increases were effective as of June 16, 2007, and remained in effect
for an initial period until July 19, 2008, pending a Phase II proceeding in
which the MPSC considered the results of audits of each company’s cost
allocation manual, as filed with the MPSC, to determine whether a further
adjustment to the rates was required. On July 18, 2008, the MPSC
issued one order covering the Phase II proceedings for both DPL and Pepco,
denying any further adjustment to the rates for each company, thus making
permanent the rate increases approved in the July 2007
orders. The MPSC also issued an order on August 4, 2008, further
explaining its July 18 order.
DPL and Pepco each have filed a general
notice of appeal of the MPSC July 2007 and the July 18 and
August 4, 2008 orders. The appeals challenge the MPSC’s failure
to implement permanent rates in accordance with Maryland law, and seek judicial
review of the MPSC’s denial of both companies’ rights to recover an increased
share of the PHI Service Company costs and the costs of performing a
MPSC-mandated management audit. The case currently is pending before
the Circuit Court for Baltimore City, which issued an order consolidating the
appeals on January 27, 2009. Under the procedural schedule set
by the court, Pepco and DPL will file a consolidated brief on or before March 9,2009, specifying the basis for their requested relief.
Federal Energy Regulatory
Commission
On August 18, 2008, PHI, Pepco, DPL and
ACE submitted an application with FERC for incentive rate treatments in
connection with PHI’s MAPP project. The application requested that
FERC include Construction Work in Progress of each of Pepco, DPL and ACE in its
transmission rate base, an ROE adder of 150 basis points (for a total ROE of
12.8%) and the recovery of prudently incurred costs in the event the project is
abandoned or terminated for reasons beyond the control of the
applicants. On October 31, 2008, FERC issued an order approving
the application.
Divestiture
Cases
District of Columbia
In June 2000, the DCPSC approved a
divestiture settlement under which Pepco is required to share with its District
of Columbia customers the net proceeds realized by Pepco from the sale of its
generation-related assets. An unresolved issue relating to the
application filed with the DCPSC by Pepco to implement the divestiture
settlement is whether Pepco should be required to share with customers the
excess deferred income taxes (EDIT) and accumulated deferred investment tax
credits (ADITC) associated with the sold assets and, if so, whether such sharing
would violate the normalization provisions of the Internal Revenue Code (IRC)
and its implementing regulations. As of December 31, 2008, the
District of Columbia allocated portions of EDIT and ADITC associated with the
divested generating assets were approximately $7 million and
$6 million, respectively. Other issues in the divestiture
proceeding deal with the treatment of internal costs and cost allocations as
deductions from the gross proceeds of the divestiture.
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Pepco believes that a sharing of EDIT
and ADITC would violate the IRS normalization rules. Under these
rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more
quickly than on a straight line basis over the book life of the related
assets. Since the assets are no longer owned by Pepco, there is no
book life over which the EDIT and ADITC can be returned. If Pepco
were required to share EDIT and ADITC and, as a result, the normalization rules
were violated, Pepco would be unable to use accelerated depreciation on District
of Columbia allocated or assigned property. In addition to sharing
with customers the generation-related EDIT and ADITC balances, Pepco would have
to pay to the IRS an amount equal to Pepco’s District of Columbia jurisdictional
generation-related ADITC balance ($6 million as of December 31, 2008),
as well as its District of Columbia jurisdictional transmission and
distribution-related ADITC balance ($3 million as of December 31,2008) in each case as those balances exist as of the later of the date a DCPSC
order is issued and all rights to appeal have been exhausted or lapsed, or the
date the DCPSC order becomes operative.
In March 2008, the IRS approved final
regulations, effective March 20, 2008, which allow utilities whose assets
cease to be utility property (whether by disposition, deregulation or otherwise)
to return to its utility customers the normalization reserve for EDIT and part
or all of the normalization reserve for ADITC. This ruling applies to
assets divested after December 21, 2005. For utility property
divested on or before December 21, 2005, the IRS stated that it would
continue to follow the holdings set forth in private letter rulings prohibiting
the flow through of EDIT and ADITC associated with the divested
assets. Pepco made a filing in April 2008, advising the DCPSC of the
adoption of the final regulations and requesting that the DCPSC issue an order
consistent with the IRS position. If the DCPSC issues the requested
order, no accounting adjustments to the gain recorded in 2000 would be
required.
As part of the proposal filed with the
DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant
settlement, as discussed above under “Proceeds from Settlement of Mirant
Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the
issues related to the divestiture of Pepco’s generating assets that remain
outstanding. On December 12, 2008, the DCPSC issued a Notice of
Proposed Rulemaking, which gave notice of Pepco’s November 2008 sharing of
proceeds filing and requested comments. The public comment period for
the proposed rules has expired without any comments being
submitted. This matter remains pending before the DCPSC.
Pepco believes that its calculation of
the District of Columbia customers’ share of divestiture proceeds is
correct. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to make additional gain-sharing payments to
District of Columbia customers, including the payments described above related
to EDIT and ADITC. Such additional payments (which, other than the
EDIT and ADITC related payments, cannot be estimated) would be charged to
expense in the quarter and year in which a final decision is rendered and could
have a material adverse effect on Pepco’s and PHI’s results of operations for
those periods. However, neither PHI nor Pepco believes that
additional gain-sharing payments, if any, or the ADITC-related payments to the
IRS, if required, would have a material adverse impact on its financial position
or cash flows.
Maryland
Pepco filed its divestiture proceeds
plan application with the MPSC in April 2001. The principal
issue in the Maryland case is the same EDIT and ADITC sharing issue that has
been
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raised in
the District of Columbia case. See the discussion above under
“Divestiture Cases — District of Columbia.” As of December 31,2008, the Maryland allocated portions of EDIT and ADITC associated with the
divested generating assets were approximately $9 million and
$10 million, respectively. Other issues deal with the treatment
of certain costs as deductions from the gross proceeds of the
divestiture. In November 2003, the Hearing Examiner in the
Maryland proceeding issued a proposed order with respect to the application that
concluded that Pepco’s Maryland divestiture settlement agreement provided for a
sharing between Pepco and customers of the EDIT and ADITC associated with the
sold assets. Pepco believes that such a sharing would violate the
normalization rules (as discussed above) and would result in Pepco’s inability
to use accelerated depreciation on Maryland allocated or assigned
property. If the proposed order is affirmed, Pepco would have to
share with its Maryland customers, on an approximately 50/50 basis, the Maryland
allocated portion of the generation-related EDIT ($9 million as of
December 31, 2008), and the Maryland-allocated portion of
generation-related ADITC. Furthermore, Pepco would have to pay to the
IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC
balance ($10 million as of December 31, 2008), as well as its Maryland
retail jurisdictional ADITC transmission and distribution-related balance
($6 million as of December 31, 2008), in each case as those balances
exist as of the later of the date a MPSC order is issued and all rights to
appeal have been exhausted or lapsed, or the date the MPSC order becomes
operative. The Hearing Examiner decided all other issues in favor of
Pepco, except for the determination that only one-half of the severance payments
that Pepco included in its calculation of corporate reorganization costs should
be deducted from the sales proceeds before sharing of the net gain between Pepco
and customers.
In December 2003, Pepco appealed
the Hearing Examiner’s decision to the MPSC as it relates to the treatment of
EDIT and ADITC and corporate reorganization costs. The MPSC has not
issued any ruling on the appeal, pending completion of the IRS rulemaking
regarding sharing of EDIT and ADITC related to divested assets. Pepco
made a filing in April 2008, advising the MPSC of the adoption of the final IRS
normalization regulations (described above under “Divestiture Cases — District
of Columbia”) and requesting that the MPSC issue a ruling on the appeal
consistent with the IRS position. If the MPSC issues the requested
ruling, no accounting adjustments to the gain recorded in 2000 would be
required. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to share with its customers approximately 50
percent of the EDIT and ADITC balances described above in addition to the
additional gain-sharing payments relating to the disallowed severance
payments. Such additional payments would be charged to expense in the
quarter and year in which a final decision is rendered and could have a material
adverse effect on Pepco’s and PHI’s results of operations for those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
As part of the proposal filed with the
MPSC in November 2008 concerning the sharing of the proceeds of the Mirant
settlement, as discussed above under “Proceeds from Settlement of Mirant
Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the
issues related to the divestiture of Pepco’s generating assets that remain
outstanding.
On February 17, 2009, Pepco, the
Maryland OPC and the MPSC staff filed a settlement agreement with the
MPSC. The settlement agreement, among other things, provides that
Pepco will be allowed to retain the EDIT and ADITC reserves associated with
Pepco’s divested
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generating
assets and that none of those amounts will be available for sharing with Pepco’s
Maryland customers. The matter is pending before the
MPSC.
ACE
Sale of B.L. England Generating Facility
In February 2007, ACE completed
the sale of the B.L. England generating facility to RC Cape May Holdings, LLC
(RC Cape May), an affiliate of Rockland Capital Energy Investments,
LLC. In July 2007, ACE received a claim for indemnification from
RC Cape May under the purchase agreement in the amount of
$25 million. RC Cape May contends that one of the assets it
purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt
Refining Co. (Citgo), has been declared by Citgo to have been terminated due to
a failure by ACE to renew the contract in a timely manner. RC Cape
May has commenced an arbitration proceeding against Citgo seeking a
determination that the TSA remains in effect and has notified ACE of the
proceeding. The claim for indemnification seeks payment from ACE in
the event the TSA is held not to be enforceable against Citgo. While
ACE believes that it has defenses to the indemnification claim, should the
arbitrator rule that the TSA has terminated, the outcome of this matter is
uncertain. ACE notified RC Cape May of its intent to participate in
the pending arbitration. The arbitration hearings were conducted in
November 2008. A decision is expected late in the second quarter of
2009, after the filing of post-hearing memoranda in the first quarter of
2009.
DPL
Sale of Virginia Retail Electric Distribution and Wholesale Transmission
Assets
In January 2008, DPL completed
(i) the sale of its retail electric distribution assets on the Eastern
Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price
of approximately $49 million, after closing adjustments, and (ii) the
sale of its wholesale electric transmission assets located on the Eastern Shore
of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of
approximately $5 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 purchased
(including, in the A&N transaction, most environmental
liabilities). A&N delayed final payment of approximately
$3 million, which was due on June 2, 2008, due to a dispute in the
final true-up amounts. On October 21, 2008, DPL and A&N
entered into a Settlement Agreement pursuant to which A&N paid
$3 million to DPL, and an additional $1 million was distributed to DPL
pursuant to an escrow agreement.
General
Litigation
In 1993, Pepco was served with Amended
Complaints filed in the state Circuit Courts of Prince George’s County,
Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated
proceedings known as “In re: Personal Injury Asbestos
Case.” Pepco and other corporate entities were brought into these
cases on a theory of premises liability. Under this theory, the
plaintiffs argued that Pepco was negligent in not providing a safe work
environment for employees or its contractors, who allegedly were exposed to
asbestos while working on Pepco’s property. Initially, a total of
approximately 448 individual plaintiffs added Pepco to their
complaints. While the pleadings are not entirely clear, it appears
that each plaintiff sought $2 million in compensatory damages and
$4 million in punitive damages from each defendant.
Since the initial filings in 1993,
additional individual suits have been filed against Pepco, and significant
numbers of cases have been dismissed. As a result of two motions to
dismiss,
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numerous
hearings and meetings and one motion for summary judgment, Pepco has had
approximately 400 of these cases successfully dismissed with prejudice, either
voluntarily by the plaintiff or by the court. As of December 31,2008, there are approximately 180 cases still pending against Pepco in the State
Courts of Maryland, of which approximately 90 cases were filed after
December 19, 2000, and were tendered to Mirant for defense and
indemnification pursuant to the terms of the Asset Purchase and Sale Agreement
between Pepco and Mirant under which Pepco sold its generation assets to Mirant
in 2000.
While the aggregate amount of monetary
damages sought in the remaining suits (excluding those tendered to Mirant) is
approximately $360 million, PHI and Pepco believe the amounts claimed by
the remaining plaintiffs are greatly exaggerated. The amount of total
liability, if any, and any related insurance recovery cannot be determined at
this time; however, based on information and relevant circumstances known at
this time, neither PHI nor Pepco believes these suits will have a material
adverse effect on its financial position, results of operations or cash
flows. However, if an unfavorable decision were rendered against
Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial
position, results of operations or cash flows.
Cash
Balance Plan Litigation
In 1999, Conectiv established a cash
balance retirement plan to replace defined benefit retirement plans then
maintained by ACE and DPL. Following the acquisition by Pepco of
Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI
Retirement Plan. In September 2005, three management employees
of PHI Service Company filed suit in the U.S. District Court for the District of
Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and
Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class
of management employees who did not have enough age and service when the Cash
Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits
would be calculated pursuant to the terms of the predecessor plans sponsored by
ACE and DPL. A fourth plaintiff was added to the case to represent
DPL-legacy employees who were not eligible for grandfathered
benefits.
The plaintiffs challenged the design of
the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash
Balance Sub-Plan was invalid and that the accrued benefits of each member of the
class should be calculated pursuant to the terms of the predecessor
plans. Specifically, the complaint alleged that the use of a variable
rate to compute the plaintiffs’ accrued benefit under the Cash Balance Sub-Plan
resulted in reductions in the accrued benefits that violated
ERISA. The complaint also alleged that the benefit accrual rates and
the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as
did the notice that was given to plan participants upon implementation of the
Cash Balance Sub-Plan.
In
September 2007, the Delaware District Court issued an order granting
summary judgment in favor of the PHI Parties. In October 2007,
the plaintiffs filed an appeal of the decision to the U.S. Court of Appeals for
the Third Circuit (the Third Circuit). In November 2008, the Third
Circuit affirmed the Delaware District Court ruling. On December 16,2008, the Third Circuit denied a petition for rehearing filed by the
plaintiffs. Plaintiffs have until March 23, 2009, to petition
the U.S. Supreme Court for review of the Third Circuit decision.
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If the plaintiffs were to prevail in
this litigation, the ABO and projected benefit obligation (PBO) calculated in
accordance with SFAS No. 87 each would increase by approximately
$12 million, assuming no change in benefits for persons who have already
retired or whose employment has been terminated and using actuarial valuation
data as of the time the suit was filed. The ABO represents the
present value that participants have earned as of the date of
calculation. This means that only service already worked and
compensation already earned and paid is considered. The PBO is
similar to the ABO, except that the PBO includes recognition of the effect that
estimated future pay increases would have on the pension plan
obligation.
Environmental
Litigation
PHI, through its subsidiaries, is
subject to regulation by various federal, regional, state, and local authorities
with respect to the environmental effects of its operations, including air and
water quality control, solid and hazardous waste disposal, and limitations on
land use. In addition, federal and state statutes authorize
governmental agencies to compel responsible parties to clean up certain
abandoned or unremediated hazardous waste sites. PHI’s subsidiaries
may incur costs to clean up currently or formerly owned facilities or sites
found to be contaminated, as well as other facilities or sites that may have
been contaminated due to past disposal practices. Although penalties
assessed for violations of environmental laws and regulations are not
recoverable from customers of the operating utilities, environmental clean-up
costs incurred by Pepco, DPL and ACE would be included by each company in its
respective cost of service for ratemaking purposes.
Metal Bank/Cottman Avenue
Site. In the early 1970s, both Pepco and DPL sold scrap
transformers, some of which may have contained some level of PCBs, to a metal
reclaimer operating at the Metal Bank/Cottman Avenue site in Philadelphia,
Pennsylvania, owned by a nonaffiliated company. In 1987, Pepco and
DPL were notified by the EPA that they, along with a number of other utilities
and non-utilities, were potentially responsible parties (PRPs) in connection
with the PCB contamination at the site.
In 1997, the EPA issued a Record of
Decision that set forth a remedial action plan for the site with estimated
implementation costs of approximately $17 million. In May 2003,
two of the potentially liable owner/operator entities filed for reorganization
under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the
bankruptcy court confirmed a reorganization plan that incorporates the terms of
a settlement among the two debtor owner/operator entities, the United States and
a group of utility PRPs including Pepco (the Utility PRPs). Under the
bankruptcy settlement, the reorganized entity/site owner will pay a total of
approximately $13 million to remediate the site (the Bankruptcy
Settlement).
In March 2006, the U.S. District Court
for the Eastern District of Pennsylvania approved global consent decrees for the
Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the
Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and
two owner/operators of the site. Under the terms of the settlement,
the two owner/operators will make payments totaling approximately
$6 million to the U.S. Department of Justice and totaling approximately
$4 million to the Utility PRPs. The Utility PRPs will perform
the remedy at the site and will be able to draw on the approximately
$13 million from the Bankruptcy Settlement to accomplish the remediation
(the Bankruptcy Funds). The Utility PRPs will contribute funds to the
extent remediation costs exceed the Bankruptcy Funds available. The
Utility PRPs also will be liable for EPA costs associated with overseeing the
monitoring and
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operation
of the site remedy after the remedy construction is certified to be complete and
also the cost of performing the “5 year” review of site conditions required by
the Comprehensive Environmental Response, Compensation, and Liability Act of
1980. Any Bankruptcy Funds not spent on the remedy may be used to
cover the Utility PRPs’ liabilities for future costs. No parties are
released from potential liability for damages to natural resources.
As of December 31, 2008, Pepco had
accrued approximately $2 million to meet its liability for a remedy at the
Metal Bank/Cottman Avenue site. While final costs to Pepco of the
settlement have not been determined, Pepco believes that its liability at this
site will not have a material adverse effect on its financial position, results
of operations or cash flows.
In 1999, DPL entered into a de minimis
settlement with the EPA and paid less than a million dollars to resolve its
liability for cleanup costs at the Metal Bank/Cottman Avenue
site. The de minimis settlement did not resolve DPL’s responsibility
for natural resource damages, if any, at the site. DPL believes that
any liability for natural resource damages at this site will not have a material
adverse effect on its financial position, results of operations or cash
flows.
Delilah Road Landfill
Site. In 1991, the New Jersey Department of Environmental
Protection (NJDEP) identified ACE as a PRP at the Delilah Road Landfill site in
Egg Harbor Township, New Jersey. In 1993, ACE, along with two other
PRPs, signed an administrative consent order with NJDEP to remediate the
site. The soil cap remedy for the site has been implemented and in
August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not
to Sue for the site. Among other things, the NFA requires the PRPs to
monitor the effectiveness of institutional (deed restriction) and engineering
(cap) controls at the site every two years. In September 2007,
NJDEP approved the PRP group’s petition to conduct semi-annual, rather than
quarterly, ground water monitoring for two years and deferred until the end of
the two-year period a decision on the PRP group’s request for annual groundwater
monitoring thereafter. In August 2007, the PRP group agreed to
reimburse the costs of the EPA in the amount of $81,400 in full satisfaction of
EPA’s claims for all past and future response costs relating to the site (of
which ACE’s share is one-third). Effective April 2008, EPA and the
PRP group entered into a settlement agreement which will allow EPA to reopen the
settlement in the event of new information or unknown conditions at the
site. Based on information currently available, ACE anticipates that
its share of additional cost associated with this site for post-remedy operation
and maintenance will be approximately $555,000 to $600,000. On
November 23, 2008, Lenox, Inc., a member of the PRP group, filed a
bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE
filed a proof of claim in the Lenox bankruptcy case in February
2009. ACE believes that its liability for post-remedy operation and
maintenance costs will not have a material adverse effect on its financial
position, results of operations or cash flows regardless of the impact of the
Lenox bankruptcy.
Frontier Chemical
Site. In June 2007, ACE received a letter from the New
York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP
at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y.
based on hazardous waste manifests indicating that ACE sent in excess of 7,500
gallons of manifested hazardous waste to the site. ACE has entered
into an agreement with the other parties identified as PRPs to form a PRP group
and has informed NYDEC that it has entered into good faith negotiations with the
PRP group to address ACE’s responsibility at the site. ACE believes
that its responsibility at the site will not have a material adverse effect on
its financial position, results of operations or cash flows.
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Franklin Slag Pile Superfund
Site. On November 26, 2008, ACE received a general notice
letter from EPA concerning the Franklin Slag Pile Superfund Site in
Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability
with respect to the site. If liable, ACE would be responsible for
reimbursing EPA for clean-up costs incurred and to be incurred by the agency and
for the costs of implementing an EPA-mandated remedy. The EPA’s
claims are based on ACE’s sale of boiler slag from the B.L. England generating
facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983
(ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag
Pile Site). EPA further claims that the boiler slag ACE sold to MDC
contained copper and lead, which are hazardous substances under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
(CERCLA), and that the sales transactions may have constituted an arrangement
for the disposal or treatment of hazardous substances at the site, which could
be a basis for liability under CERCLA. The EPA’s letter also states
that to date its expenditures for response measures at the site exceed
$6 million. EPA estimates approximately $6 million as the
cost for future response measures it recommends. ACE understands that
the EPA sent similar general notice letters to three other companies and various
individuals.
ACE believes that the B.L. England
boiler slag sold to MDC was a valuable material with various industrial
applications, and therefore, such sale was not an arrangement for the disposal
or treatment of any hazardous substances as would be necessary to constitute a
basis for liability under CERCLA. ACE intends to contest any
such claims made by the EPA. At this time ACE cannot predict how EPA
will proceed or what portion, if any, of the Franklin Slag Pile Site response
costs EPA would seek to recover from ACE.
Deepwater Generating Station
Revocation Order. In December 2005, NJDEP issued a Title
V operating permit (the 2005 Permit) to Deepwater Generating Station (Deepwater)
owned by Conectiv Energy. Conectiv Energy appealed several provisions
of the 2005 Permit and a revised Title V operating permit issued in 2008 (the
2008 Permit). Administrative litigation concerning the provisions of
the operating permit is ongoing. In February 2008, NJDEP issued an
Administrative Order of Revocation and Notice of Civil Administrative Penalty
Assessment (the First Revocation Order) revoking the Deepwater operating
permit. The First Revocation Order is based on the NJDEP’s contention
that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen
chloride (HCl) and total suspended particles (TSP) during a December 2007
stack test. The First Revocation Order also assessed a $20,000
penalty for the HCl incident and a $10,000 penalty for the TSP
incident. Conectiv Energy has filed an appeal of both the revocation
order and the penalty with the Office of Administrative
Law. Subsequent stack tests have confirmed that Unit 6/8 complies
with its TSP emission limit and Conectiv Energy and NJDEP entered into a
settlement agreement that resolves the $10,000 penalty for TSP from the First
Order.
In July 2008, NJDEP issued an
Administrative Order of Revocation and Notice of Civil Administrative Penalty
Assessment (the Second Revocation Order) revoking the Deepwater operating
permit. The Second Revocation Order is based on the NJDEP’s
contention that Deepwater Unit 6/8 operated in violation of its emission limit
for particulate matter less than 10 microns (PM-10) during the
December 2007 stack test. The Second Revocation Order also
assessed a penalty for the incident in the amount of
$10,000. Conectiv Energy has filed an appeal of both the revocation
order and the penalty with the Office of Administrative Law. NJDEP
has issued a letter stating that elevated PM-10 levels indicated during the July
2008 stack
224
PEPCO
HOLDINGS
test were
the result of laboratory error. Subsequent stack testing has shown
that Unit 6/8 complies with its PM-10 emission limit.
In September 2008, NJDEP issued an
additional and separate Administrative Order of Revocation and Notice of Civil
Administrative Penalty Assessment (the Third Revocation Order) requiring
Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit
or in the alternative revoking Unit 6/8’s operating permit effective
October 21, 2008. The Third Revocation Order is based on the
NJDEP’s contention that Unit 6/8 violated the HCl limit on 106 days between
December 5, 2007 and April 24, 2008 stack tests. The Third
Revocation Order assessed a penalty in the amount of
$5.3 million. Conectiv Energy has appealed both the revocation
order and the penalty with the Office of Administrative Law. The
effectiveness of the three revocation orders has been stayed by the NJDEP
through February 28, 2009. On February 23, 2009, NJDEP
extended the stay of the three revocation orders until May 28,2009.
Conectiv Energy is operating Deepwater
6/8 while firing coal at a reduced load, or at full load with lime injection, to
comply with the challenged HCl permit limit at all potential coal chloride
contents. Operation with lime injection was authorized by the
Environmental Improvement Pilot Test permit issued by NJDEP in September 2008,
which facilitates assessment of the feasibility and practicality of hydrated
lime injection technology in controlling HCl emissions from Unit 6/8 at full
load without significantly impacting boiler operations. Testing
indicates that hydrated lime injection technology effectively controls HCl
emissions without significantly impacting boiler operations and without
affecting Conectiv Energy’s ability to meet emissions limits for other
parameters. Conectiv Energy has not yet determined the costs of
converting the hydrated lime injection from a temporary pollution control device
to a permanent pollution control device.
Conectiv Energy believes that it has
strong legal arguments that NJDEP cannot revoke the permit prior to an
administrative hearing and believes that the probability of a complete shut-down
of the unit is low because the unit appears to be in compliance with the HCl
limit. In addition, Conectiv Energy believes that its appeal asserts
strong arguments against the assessment of the $5.3 million
penalty.
Appeal of Delaware Multi-Pollutant
Regulations. In November 2006, Delaware Department of Natural
Resources and Environmental Control (DNREC) adopted multi-pollutant regulations
to require large coal-fired and residual oil-fired electric generating units to
develop control strategies to address air quality in Delaware. In
December 2006, Conectiv Energy filed a complaint with the Delaware Superior
Court seeking review of the adoption of the new regulations. In
December 2008, Conectiv Energy reached a settlement with DNREC. Under
the terms of the settlement agreement, Conectiv Energy will comply with the
nitrogen oxide, sulfur dioxide (SO2) and
mercury emission reduction requirements required by the regulations by the
regulatory compliance dates, except that it will comply with the Phase II
mercury emission limit by January 1, 2012, which is one year earlier than the
regulatory compliance date. In addition, DNREC has agreed to increase
the annual SO2 mass
emission limit as it relates to the Edge Moor residual oil-fired generating
unit.
Appeal of New Jersey Flood Hazard
Regulations. In November 2007, NJDEP adopted amendments to the
agency’s 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, which took effect November 5, 2007,
impose a new regulatory program to
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PEPCO
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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 filed an appeal of these regulations with the Appellate
Division of the Superior Court of New Jersey on November 3, 2008. See
Item I “Business – Environmental Matters– Air Quality Regulation – Sulfur
Dioxide, Nitrogen Oxide, Mercury and Nickel Emissions.”
IRS
Examination of Like-Kind Exchange Transaction
In 2001, Conectiv and certain of its
subsidiaries (the Conectiv Group) were engaged in the implementation of a
strategy to divest non-strategic electric generating facilities and replace
these facilities with mid-merit electric generating capacity. As part
of this strategy, the Conectiv Group exchanged its interests in two older
coal-fired plants for the more efficient gas-fired Hay Road II generating
facility owned by an unaffiliated third party. For tax purposes,
Conectiv treated the transaction as a “like-kind exchange” under IRC Section
1031. As a result, approximately $88 million of taxable gain was
deferred for federal income tax purposes.
The transaction was examined by the IRS
as part of the normal Conectiv tax audit. In May 2006, the IRS issued
a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002
income tax returns, in which the IRS disallowed the qualification of the
transaction as an exchange under IRC Section 1031. In July 2006,
Conectiv filed a protest of this disallowance to the U.S. Office of Appeals of
the IRS (Appeals Office).
In October 2008, Conectiv and the
IRS agreed on a settlement under which Conectiv will pay approximately $2
million of tax and $1 million of interest (pre-tax) representing tax and
interest due for the years settled with the IRS. PHI will recover the
payment of this tax through additional tax depreciation deductions over the
remaining tax life of the facility. PHI’s reserve on this issue was
more conservative than the actual settlement with the IRS. As a
result, PHI reversed a total of $5 million (after-tax) in excess accrued
interest in the fourth quarter of 2008.
PHI’s
Cross-Border Energy Lease Investments
Between 1994 and 2002, Potomac Capital Investment
Corporation (PCI), a subsidiary of PHI, entered into eight cross-border energy
lease investments involving public utility assets (primarily consisting of
hydroelectric generation and coal-fired electric generation facilities and
natural gas distribution networks) located outside of the United
States. Each of these investments is structured as a sale and
leaseback transaction commonly referred to as a sale-in/lease-out or SILO
transaction. Prior to the reassessment discussed below, PHI had
historically derived approximately $74 million per year in tax benefits from
these eight cross-border energy lease investments (reflecting 100% of the tax
benefits) to the extent that rental income under the leases is exceeded by the
depreciation deductions on the purchase price of the assets and interest
deductions on the non-recourse debt financing (obtained by PCI to fund a
substantial portion of the purchase price of the assets). PHI’s
annual tax benefits are now approximately $56 million after giving effect to the
reassessment. As of December 31, 2008, PHI’s equity investment
in its cross-border energy leases was approximately $1.3 billion which included
the impact of the reassessment discussed below. During the period
from January 1, 2001 to December 31, 2008, PHI has derived
approximately $461 million in federal income tax benefits from the
depreciation
226
PEPCO
HOLDINGS
and
interest deductions in excess of rental income with respect to these
cross-border energy lease investments, which includes the effect of the
reassessment discussed below.
In 2005, the Treasury Department and
IRS issued Notice 2005-13 identifying sale-leaseback transactions with certain
attributes entered into with tax-indifferent parties as tax avoidance
transactions, and the IRS announced its intention to disallow the associated tax
benefits claimed by the investors in these transactions. PHI’s
cross-border energy lease investments, each of which is with a tax-indifferent
party, have been under examination by the IRS as part of the normal PHI federal
income tax audits. In the final RAR issued in June 2006 in
connection with the audit of PHI’s 2001 and 2002 income tax returns, the IRS
disallowed the depreciation and interest deductions in excess of rental income
claimed by PHI with respect to six of its cross-border energy lease
investments. In addition, the IRS has sought to recharacterize the
leases as loan transactions as to which PHI would be subject to original issue
discount income. PHI is protesting the IRS adjustments and the
unresolved audit issues have been forwarded to the Appeals
Office. PHI is in the early stages of discussions with the Appeals
Office. If these discussions are unsuccessful, PHI currently intends
to pursue litigation proceedings against the IRS to defend its tax
position. While the audits of PHI’s federal income tax returns for
subsequent tax years are ongoing or have not yet commenced, PHI anticipates that
the IRS will take the same position with respect to each of the subsequent years
on all eight of its cross-border energy lease investments.
In the last several years, IRS
challenges to certain cross-border lease transactions have been the subject of
litigation. This litigation has resulted in several decisions in
favor of the IRS, including two decisions in the second quarter of
2008. In one of the cases decided in the second quarter relating to a
lease-in/lease-out transaction, a United States Court of Appeals upheld a lower
court decision in favor of the IRS to disallow the tax benefits taken by the
taxpayer. In the second case, a United States District Court rendered
an opinion concerning a SILO transaction in which it upheld the IRS’s
disallowance of tax benefits taken by the taxpayer. Under
FIN 48, “Accounting for Uncertainty in Income Taxes,” the financial
statement recognition of an uncertain tax position is permitted only if it is
more likely than not that the position will be sustained. Further,
under FSP 13-2, “Accounting for a Change in the Timing of Cash Flows Relating to
Income Taxes Generated by a Leveraged-lease Transaction,” a company is required
to assess on a periodic basis the likely outcome of tax positions relating to
its cross-border energy lease investments and, if there is a change or a
projected change in the timing of the tax benefits generated by the
transactions, the company is required to recalculate the value of its equity
investment.
While PHI believes that its tax
position with regard to its cross-border energy lease investments is appropriate
based on applicable statutes, regulations and case law, after evaluating the
court rulings described above, PHI at June 30, 2008 reassessed the
sustainability of its tax position and revised its assumptions regarding the
estimated timing of the tax benefits from its cross-border energy lease
investments. Based on this reassessment, PHI for the quarter ended
June 30, 2008, recorded an after-tax charge to net income of $93 million,
consisting of the following components:
·
A
non-cash pre-tax charge of $124 million ($86 million after tax) under FSP
13-2 to reduce the equity value of these cross-border energy lease
investments. This
227
PEPCO
HOLDINGS
pre-tax
charge has been recorded in the Consolidated Statement of Earnings as a
reduction in other operating revenue.
·
A
non-cash charge of $7 million after-tax to reflect the anticipated
additional interest expense under FIN 48 on the estimated federal and
state income tax that would be payable for the period January 1, 2001
through June 30, 2008, based on the revised assumptions regarding the
estimated timing of the tax benefits. This after-tax charge has
been recorded in the Consolidated Statement of Earnings as an increase in
income tax expense.
The
charge pursuant to FSP 13-2 reflects changes to the book equity value of the
cross-border energy lease investments and the pattern of recognizing the related
cross-border energy lease income. This amount will be recognized as
income over the remaining term of the affected leases, which expire between 2017
and 2047. The tax benefits associated with the lease transactions
represent timing differences that do not change the aggregate amount of the
lease net income over the life of the transactions. Consistent with
the revised assumptions regarding the estimated timing of the tax benefits, PHI
reduced the tax benefits recorded on its 2007 tax return filed in
September 2008 and accordingly paid additional federal and state income
taxes. Other than these payments made with the 2007 tax return and
estimated tax payments made in 2008 associated with the reduced tax benefits,
PHI has made no additional cash payments of federal or state income taxes or
interest thereon as a result of the reassessment discussed
above. Whether PHI makes an additional payment, and the amount and
the timing thereof, will depend on a number of factors, including PHI’s
litigation strategy, whether a settlement with the IRS can be reached or whether
the company decides to deposit funds with the IRS to avoid higher interest
costs, until the issue is resolved. PHI is continuing to defend
vigorously its tax position with the IRS.
In connection with the recording of the
above adjustment, PHI calculated as of June 30, 2008, the additional
non-cash charge to earnings that would have been recorded resulting from the
disallowance of the entire amount of the tax benefits from the depreciation and
interest deductions in excess of rental income and the recharacterization of the
transactions as loans over the period from January 1, 2001 through the end
of the lease term. PHI would have incurred an additional non-cash charge to
earnings at June 30, 2008 of approximately $346 million consisting
of:
·
A
non-cash charge of $324 million ($293 million after tax) under FSP 13-2 to
further reduce the equity value of these cross-border energy lease
investments.
·
A
non-cash charge of $53 million after-tax to reflect the anticipated
additional interest expense under FIN 48 on the estimated federal and
state income tax for the period from January 1, 2001 through
June 30, 2008.
As of
December 31, 2008, no changes in the assumptions have occurred that would
materially impact these estimates.
In the event of the total disallowance
of the tax benefits and the imputing of original issue discount income due to
the recharacterization of the leases as loans, PHI would have been obligated to
pay, as of December 31, 2008, approximately $520 million in additional federal
and
228
PEPCO
HOLDINGS
state
taxes and $83 million of interest. In addition, the IRS could require
PHI to pay a penalty of up to 20% on the amount of additional taxes due. PHI
anticipates that any additional taxes that it would be required to pay as a
result of the disallowance of prior deductions or a recharacterization of the
leases as loans would be recoverable in the form of lower taxes over the
remaining term of the investments.
On August 7, 2008, PHI received a
global settlement offer from the IRS with respect to its SILO
transactions. PHI is continuing its discussion with the Appeals
Office and has not responded to the global settlement offer.
IRS Mixed Service Cost
Issue
During 2001, Pepco, DPL, and ACE
changed their methods of accounting with respect to capitalizable construction
costs for income tax purposes. The change allowed the companies to
accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $205
million (consisting of $94 million for Pepco, $62 million for DPL, and $49
million for ACE) for the companies, primarily attributable to their 2001 tax
returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require
Pepco, DPL, and ACE to change their method of accounting with respect to
capitalizable construction costs for income tax purposes for tax periods
beginning in 2005. Based on those proposed regulations, PHI in its
2005 federal tax return adopted an alternative method of accounting for
capitalizable construction costs that management believed would be acceptable to
the IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which was
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’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
U.S. Office of Appeals of the IRS.
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. In June 2008, PHI
received from the IRS an offer of settlement pertaining to each of Pepco, DPL
and ACE for the tax years 2001 through 2004. PHI is substantially in
agreement with this proposed settlement. Based on the terms of the
proposal, PHI expects the final settlement amount to be less than the $121
million previously deposited.
On the
basis of the tentative settlement, PHI updated its estimated liability related
to mixed service costs and as a result, recorded in the quarter ended June 30,2008, a net reduction in its liability for unrecognized tax benefits of $19
million and recognized after-tax interest income of $7 million.
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PEPCO
HOLDINGS
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 that they have entered into in the normal course of
business to facilitate commercial transactions with third parties as discussed
below.
As of December 31, 2008, Pepco Holdings
and its subsidiaries were parties to a variety of agreements pursuant to which
they were guarantors for standby letters of credit, performance residual value,
and other commitments and obligations. The commitments and
obligations, in millions of dollars, were as follows:
Guarantor
PHI
DPL
ACE
Other
Total
(Millions
of Dollars)
Energy
marketing obligations of Conectiv Energy (a)
$
168
$
-
$
-
$
-
$
168
Energy
procurement obligations of Pepco Energy
Services (a)
243
-
-
-
243
Guaranteed
lease residual values
(b)
-
3
3
1
7
Other
(c)
2
-
-
1
3
Total
$
413
$
3
$
3
$
2
$
421
(a)
Pepco
Holdings has contractual commitments for performance and related payments
of Conectiv Energy and Pepco Energy Services to counterparties under
routine energy sales and procurement obligations, including retail
customer load obligations of Pepco Energy Services and requirements under
BGS contracts entered into by Conectiv Energy with
ACE.
(b)
Subsidiaries
of Pepco Holdings have guaranteed residual values in excess of fair value
of certain equipment and fleet vehicles held through lease
agreements. As of December 31, 2008, obligations under the
guarantees were approximately $7 million. Assets leased
under agreements subject to residual value guarantees are typically for
periods ranging from 2 years to 10 years. Historically,
payments under the guarantees have not been made by the guarantor as,
under normal conditions, the contract runs to full term at which time the
residual value is minimal. As such, Pepco Holdings believes the
likelihood of payment being required under the guarantee is
remote.
(c)
Other
guarantees consist of:
·
Pepco
Holdings has guaranteed a subsidiary building lease of $2 million. Pepco
Holdings does not expect to fund the full amount of the exposure under the
guarantee.
·
PCI
has guaranteed facility rental obligations related to contracts entered
into by Starpower Communications LLC, a joint venture in which
PCI, prior to December 2004, had a 50% interest. As
of December 31, 2008, the guarantees cover the remaining $1 million in
rental obligations.
Pepco Holdings and certain of its
subsidiaries have entered into various indemnification agreements related to
purchase and sale agreements and other types of contractual agreements with
vendors and other third parties. These indemnification agreements
typically cover environmental, tax, litigation and other matters, as well as
breaches of representations, warranties and covenants set forth in these
agreements. Typically, claims may be made by third parties under
these indemnification agreements over various periods of time depending on the
nature of the claim. The maximum potential exposure under these
indemnification agreements can range from a specified dollar amount to an
unlimited amount depending on the nature of the claim and the particular
transaction. The total maximum potential amount of future payments
under these indemnification agreements is not estimable due to several factors,
including uncertainty as to whether or when claims may be made under these
indemnities.
As of December 31, 2008, Pepco
Holdings’ contractual obligations under non-derivative fuel and purchase power
contracts were $3,211 million in 2009, $2,902 million in 2010 to 2011, $729
million in 2012 to 2013, and $2,225 million in 2014 and after.
(17) USE
OF DERIVATIVES IN ENERGY AND INTEREST RATE HEDGING
ACTIVITIES
PHI’s Competitive Energy businesses use
derivative instruments primarily to reduce their financial exposure to changes
in the value of their assets and obligations due to commodity price
fluctuations. The derivative instruments used by the Competitive Energy
businesses include forward contracts, futures, swaps, and exchange-traded and
over-the-counter options. In addition, the Competitive Energy businesses also
manage commodity risk with contracts that are not classified as
derivatives. The two primary risk management objectives are (i) 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 (ii) to manage the spread between retail sales commitments and the
cost of supply used to service those commitments to ensure stable cash flows,
and lock in favorable prices and margins when they become
available.
Conectiv
Energy purchases futures, swaps, options and forward contracts to hedge price
risk in connection with the purchase of physical natural gas, oil and coal to
fuel its generation assets and for resale. Conectiv Energy also purchases
electricity swaps, options and forward contracts to hedge price risk in
connection with the purchase of electricity for delivery to requirements load
customers. Conectiv Energy sells electricity swaps, options and forward
contracts to hedge price risk in connection with electric output from its
generation fleet. Conectiv Energy accounts for most of its futures, swaps and
certain forward contracts as cash flow hedges of forecasted
transactions. Derivative contracts purchased or sold in excess of
probable quantitative limits are marked-to-market through current
earnings. All option contracts are marked-to-market through current
earnings. Certain natural gas and oil futures and swaps are used as
fair value hedges to protect physical fuel inventory. Some forward
contracts are accounted for using standard accrual accounting since these
contracts meet the requirements for normal purchase and sale accounting under
SFAS No. 133.
Pepco Energy Services purchases
electric and natural gas futures, swaps, options and forward contracts to hedge
price risk in connection with the purchase of physical natural gas and
electricity for delivery to customers. Pepco Energy Services accounts for its
futures and swap contracts as cash flow hedges of forecasted
transactions. Option contracts are marked-to-market through current
earnings. Forward contracts are accounted for using standard accrual
accounting since these contracts meet the requirements for normal purchase and
sale accounting under SFAS No. 133.
PHI and its subsidiaries also use
derivative instruments from time to time to mitigate the effects of fluctuating
interest rates on debt incurred in connection with the operation of
their
231
PEPCO
HOLDINGS
businesses. In
June 2002, PHI entered into several treasury lock transactions in anticipation
of the issuance of several series of fixed rate debt commencing in July
2002.
Cash
Flow Hedges
The table below provides detail on
effective cash flow hedges under SFAS No. 133 included in PHI’s
Consolidated Balance Sheet as of December 31, 2008. Under SFAS
No. 133, cash flow hedges are marked-to-market on the balance sheet with
corresponding adjustments to Accumulated Other Comprehensive Income. The data in
the table indicates the magnitude of the effective cash flow hedges by hedge
type (i.e., energy commodity and interest rate hedges), maximum term, and
portion expected to be reclassified to earnings during the next 12
months.
Cash
Flow Hedges Included in Accumulated Other Comprehensive Loss
Accumulated
Other Comprehensive Income (Loss) After-tax (a)
Portion
Expected
to
be Reclassified
to
Earnings during
the
Next 12 Months
Maximum
Term
Energy
Commodity
$(227)
$(151)
65
months
Interest
Rate
(25)
(3)
284
months
Total
$(252)
$(154)
(a)
Accumulated
Other Comprehensive Income as of December 31, 2008, includes a $(10)
million balance related to minimum pension liability. This
balance is not included in this table as it is not a cash flow
hedge.
The
following table shows the pre-tax gain (loss) recognized in earnings for cash
flow hedge ineffectiveness for the years ended December 31, 2008, 2007 and 2006,
respectively, and where they were reported in PHI’s Consolidated Statements of
Earnings during the periods.
2008
2007
2006
(Millions
of dollars)
Operating
Revenue
$ 3
$ (2)
$ -
Fuel
and Purchased Energy Expenses
(6)
-
-
Total
$(3)
$ (2)
$ -
For the
years ended December 31, 2008, 2007 and 2006, $1 million, $2 million and
zero, respectively, in losses were reclassified from Other Comprehensive Income
to earnings because the forecasted hedged transactions were deemed no longer
probable.
Fair
Value Hedges
In
connection with their energy commodity activities, the Competitive Energy
businesses designate certain derivatives as fair value hedges. For
derivative instruments that are designated and qualify as a fair value hedge,
the gain or loss on the derivative as well as the offsetting loss or gain on the
hedged item attributable to the hedged risk are recognized in current
earnings.
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PEPCO
HOLDINGS
The net
pre-tax gains (losses) recognized during the twelve months ended December 31,2008, 2007 and 2006 included in the Consolidated Statements of Earnings for fair
value hedges and the associated hedged items are shown in the following
table:
2008
2007
2006
(Millions
of dollars)
(Losses)
Gains on Derivative Instruments
$ (5)
$(10)
$-
Gains
(Losses) on Hedged Items
$ 5
$ 10
$-
Other
Derivative Activity
In connection with their energy
commodity activities, the Competitive Energy businesses hold certain derivatives
that do not qualify as hedges. Under SFAS No. 133, these derivatives
are recorded at fair value through earnings with corresponding adjustments on
the balance sheet.
The pre-tax gains (losses) on these
derivatives are included in “Competitive Energy Operating Revenues” and are
summarized in the following table:
Energy Commodity Activities (a)
2008
2007
2006
(Millions
of dollars)
Realized
Gains (Losses)
$ 56
$ 7
$ 26
Unrealized
Gains (Losses)
21
2
34
Total
$ 77
$ 9
$ 60
(a)
There
were no ineffective fair value hedge gains for the years ended December31, 2008, 2007 and 2006,
respectively.
As indicated in Note (3), PHI offsets
the fair value amounts recognized for derivative instruments and fair value
amounts recognized for related collateral positions executed with the same
counterparty under a master netting arrangement. The amount of cash
collateral that was offset against these net derivative positions is as
follows:
Cash
collateral pledged to counterparties with the right to
reclaim
$
205
$
-
Cash
collateral received from counterparties with the obligation to
return
53
-
As of December 31, 2008 and 2007, PHI
had no cash collateral pledged or received related to derivatives accounted for
at fair value that was not eligible for offset under master netting
arrangements.
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PEPCO
HOLDINGS
(18) ACCUMULATED
OTHER COMPREHENSIVE LOSS
A detail of the components of Pepco
Holdings’ Accumulated Other Comprehensive (Loss) Earnings is as
follows. For additional information, see the Consolidated Statements
of Comprehensive Earnings.
A detail of the income tax (benefit)
expense allocated to the components of Pepco Holdings’ Other Comprehensive
(Loss) Earnings for each year is as follows.
The quarterly data presented below
reflect all adjustments necessary in the opinion of management for a fair
presentation of the interim results. Quarterly data normally vary
seasonally because of temperature variations, differences between summer and
winter rates, and the scheduled downtime and maintenance of electric generating
units. The totals of the four quarterly basic and diluted earnings
per common share may not equal the basic and diluted earnings per common share
for the year due to changes in the number of common shares outstanding during
the year.
2008
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions,
except per share amounts)
Total
Operating Revenue
$
2,641
$
2,518
(b)
$
3,060
$
2,481
$
10,700
Total
Operating Expenses
2,418
2,404
(c)
2,785
(e)
2,325
9,932
Operating
Income
223
114
275
156
768
Other
Expenses
(71)
(71)
(76)
(82)
(300)
Income
Before Income Tax Expense
152
43
199
74
468
Income
Tax Expense
53
(a)
28
(d)
80
7
(f)
168
Net
Income
99
15
119
67
300
Basic
and Diluted Earnings
Per
Share of Common Stock
$
.49
$
.07
$
.59
$
.32
$
1.47
Cash
Dividends Per Common Share
$
.27
$
.27
$
.27
$
.27
$
1.08
2007
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions,
except per share amounts)
Total
Operating Revenue
$
2,179
$
2,084
$
2,770
(h)
$
2,333
(h)
$
9,366
Total
Operating Expenses
2,026
1,928
(g)
2,450
(g)
(i)
2,156
(g)
8,560
Operating
Income
153
156
320
177
806
Other
Expenses
(70)
(70)
(72)
(72)
(284)
Income
Before Income Tax Expense
83
86
248
105
522
Income
Tax Expense
31
29
80
(j)
48
188
Net
Income
52
57
168
57
334
Basic
and Diluted Earnings
Per
Share of Common Stock
$
.27
$
.30
$
.87
$
.29
$
1.72
Cash
Dividends Per Common Share
$
.26
$
.26
$
.26
$
.26
$
1.04
(a)
Includes
$7 million of after-tax net interest income on uncertain tax positions
primarily related to casualty
losses.
(b)
Includes
a $124 million charge ($86 million after-tax) related to the adjustment to
the equity value of cross-border energy lease investments under FSP
13-2.
(c)
Includes
a $4 million adjustment to correct an understatement of operating expenses
for prior periods dating back to February 2005 where late payment
fees were incorrectly recognized.
(d)
Includes
$7 million of after-tax interest income related to the tentative
settlement of the IRS mixed service cost issue and $2 million of after-tax
interest income received in 2008 on the Maryland state tax refund offset
by a $7 million after-tax charge for interest related to the increased tax
obligation associated with the adjustment to the equity value of
cross-border energy lease
investments.
(e)
Includes
a $9 million charge related to an adjustment in the accounting for certain
restricted stock awards granted under the Long-Term Incentive Plan (LTIP)
and a $4 million adjustment to correct an understatement of operating
expenses for prior periods dating back to May 2006 where late payment fees
were incorrectly recognized.
(f)
Includes
$11 million of after-tax net interest income on uncertain and effectively
settled tax positions (primarily associated with the final settlement with
the IRS on the like-kind exchange issue, a claim made with the IRS related
to the tax reporting for fuel over- and under-recoveries and the reversal
of the majority of the interest income recognized on uncertain tax
positions related to casualty losses in the first quarter) and a benefit
of $8 million (including a $3 million correction of prior period errors)
related to additional analysis of deferred tax balances completed in
2008.
(g)
Includes
adjustment related to timing of recognition of certain operating expenses
which were overstated by $5 million in the fourth quarter and understated
by $1 million and $4 million in the second and third quarters,
respectively.
(h)
Includes
adjustment related to timing of recognition of certain operating revenues
which were overstated by $2 million in the third quarter and understated
by $2 million in the fourth
quarter.
(i)
Includes
$33 million benefit ($20 million after-tax) from settlement of Mirant
bankruptcy claims.
(j)
Includes
$20 million benefit ($18 million net of fees) related to Maryland income
tax refund.
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PEPCO
Management’s
Report on Internal Control over Financial Reporting
The management of Pepco is responsible
for establishing and maintaining adequate internal control over financial
reporting. Because of inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Management assessed its internal
control over financial reporting as of December 31, 2008 based on the framework
in Internal Control —
Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on its assessment, the management
of Pepco concluded that its internal control over financial reporting was
effective as of December 31, 2008.
This Annual Report on Form 10-K does
not include an attestation report of Pepco’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit Pepco to provide only management’s report in
this Form 10-K.
In our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Potomac Electric
Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December31, 2008 and December 31, 2007, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2008 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a)(2) presents fairly, in
all material respects, the information set forth therein when read in
conjunction with the related financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company’s management. Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our
audits. We conducted our audits of these statements in accordance
with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
As
discussed in Note 11 to the financial statements, the company changed its manner
of accounting and reporting for uncertain tax positions in 2007.
The
accompanying Notes are an integral part of these Financial
Statements.
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PEPCO
NOTES TO FINANCIAL
STATEMENTS
POTOMAC
ELECTRIC POWER COMPANY
(1) ORGANIZATION
Potomac Electric Power Company (Pepco)
is engaged in the transmission and distribution of electricity in Washington,
D.C. and major portions of Prince George’s County and Montgomery County in
suburban Maryland. Pepco provides Default Electricity Supply, which
is the supply of electricity at regulated rates to retail customers in its
territories who do not elect to purchase electricity from a competitive
supplier, in both the District of Columbia and Maryland. Default
Electricity Supply is known as Standard Offer Service (SOS) in both the District
of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco
Holdings, Inc. (Pepco Holdings or PHI).
The
recent disruptions in the capital and credit markets have had an impact on
Pepco’s business. While these conditions have required Pepco to make
certain adjustments in its financial management activities, Pepco believes that
it currently has sufficient liquidity to fund its operations and meet its
financial obligations. These market conditions, should they continue,
however, could have a negative effect on Pepco’s financial condition, results of
operations and cash flows.
Liquidity
Requirements
Pepco depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, Pepco historically has relied on the issuance
of commercial paper and short-term notes and on bank lines of credit to
supplement internally generated cash from operations. Pepco’s primary
credit source is PHI’s $1.5 billion syndicated credit facility, under which
Pepco can borrow funds, obtain letters of credit and support the issuance of
commercial paper in an amount up to $500 million (subject to the limitation that
the total utilization by Pepco and PHI’s other utility subsidiaries cannot
exceed $625 million). This facility is in effect until May 2012 and
consists of commitments from 17 lenders, no one of which is responsible for more
than 8.5% of the total commitment.
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, Pepco has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. Given its
restricted access to the commercial paper market and the uncertainty in the
credit markets generally, Pepco borrowed $100 million under the credit facility
to create a cash reserve for future short-term operating needs at December 31,2008. After giving effect to outstanding letters of credit and
commercial paper, PHI’s utility subsidiaries have an aggregate of $843 million
in combined cash and borrowing capacity under the credit facility at December31, 2008. During the months of January and February 2009, the average
daily amount of the combined cash and borrowing capacity of PHI’s utility
subsidiaries was $831 million and ranged from a low of $673 million to a high of
$1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, Pepco
has identified a number of cash and liquidity conservation measures, including
opportunities to
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PEPCO
defer
capital expenditures due to lower than anticipated growth. Several
measures to reduce expenditures have been taken. Additional measures
could be undertaken if conditions warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, Pepco issued $250 million
in long-term debt securities in December, with the proceeds used to refund
short-term debt incurred to finance utility construction and operations on a
temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
Pepco participates in pension and
postretirement benefit plans sponsored by PHI for its
employees. While the plans have not experienced any significant
impact in terms of liquidity or counterparty exposure due to the disruption of
the capital and credit markets, the recent stock market declines have caused a
decrease in the market value of benefit plan assets in 2008. Pepco
expects to contribute approximately $170 million to the pension plan in
2009.
(2) SIGNIFICANT ACCOUNTING
POLICIES
Use of
Estimates
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States
of America (GAAP) requires management to make certain estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses,
and related disclosures of contingent assets and liabilities in the financial
statements and accompanying notes. Although Pepco believes that its
estimates and assumptions are reasonable, they are based upon information
available to management at the time the estimates are made. Actual
results may differ significantly from these estimates.
Significant matters that involve the
use of estimates include the assessment of contingencies, the calculation of
future cash flows and fair value amounts for use in asset impairment
evaluations, pension and other postretirement benefits assumptions, unbilled
revenue calculations, the assessment of the probability of recovery of
regulatory assets, and income tax provisions and
reserves. Additionally, Pepco is subject to legal, regulatory, and
other proceedings and claims that arise in the ordinary course of its
business. Pepco records an estimated liability for these proceedings
and claims when the loss is determined to be probable and is reasonably
estimable.
Change in Accounting
Estimates
During 2007, as a result of the
depreciation study presented as part of Pepco’s Maryland rate case, the Maryland
Public Service Commission (MPSC) approved new lower depreciation rates for
Pepco’s Maryland distribution assets. This resulted in lower depreciation
expense of approximately $19 million for the last six months of
2007.
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PEPCO
Revenue
Recognition
Pepco recognizes revenue upon delivery
of electricity to its customers, including amounts for services rendered, but
not yet billed (unbilled revenue). Pepco recorded amounts for
unbilled revenue of $98 million and $82 million as of December 31, 2008 and
2007, respectively. These amounts are included in “Accounts
receivable.” Pepco calculates unbilled revenue using an output based
methodology. This methodology is based on the supply of electricity
intended for distribution to customers. The unbilled revenue process
requires management to make assumptions and judgments about input factors such
as customer sales mix, temperature, and estimated power line losses (estimates
of electricity expected to be lost in the process of its transmission and
distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, and if actual results differ from
projected results, the impact could be material.
Taxes related to the consumption of
electricity by its customers, such as fuel, energy, or other similar taxes, are
components of Pepco’s tariffs and, as such, are billed to customers and recorded
in “Operating Revenues.” Accruals for these taxes by Pepco are
recorded in “Other taxes.” Excise tax related generally to the
consumption of gasoline by Pepco in the normal course of business is charged to
operations, maintenance or construction, and is de minimis.
Taxes Assessed by a
Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco’s gross
revenues were $241 million, $243 million and $223 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Long-Lived Assets
Impairment
Pepco evaluates certain long-lived
assets to be held and used (for example, equipment and real estate) to determine
if they are impaired whenever events or changes in circumstances indicate that
their carrying amount may not be recoverable. Examples of such events
or changes include a significant decrease in the market price of a long-lived
asset or a significant adverse change in the manner an asset is being used or
its physical condition. A long-lived asset to be held and used is
written down to fair value if the sum of its expected future undiscounted cash
flows is less than its carrying amount.
For long-lived assets that can be
classified as assets to be disposed of by sale, an impairment loss is recognized
to the extent that the assets’ carrying amount exceeds their fair value
including costs to sell.
Income
Taxes
Pepco, as a direct subsidiary of Pepco
Holdings, is included in the consolidated federal income tax return of
PHI. Federal income taxes are allocated to Pepco based upon the
taxable income or loss amounts, determined on a separate return
basis.
In 2006, the Financial Accounting
Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for
Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies
the
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PEPCO
criteria
for recognition of tax benefits in accordance with Statement of Financial
Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” and
prescribes a financial statement recognition threshold and measurement attribute
for a tax position taken or expected to be taken in a tax
return. Specifically, it clarifies that an entity’s tax benefits must
be “more likely than not” of being sustained prior to recording the related tax
benefit in the financial statements. If the position drops below the
“more likely than not” standard, the benefit can no longer be
recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. Pepco applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,2007.
The financial statements include
current and deferred income taxes. Current income taxes represent the amounts of
tax expected to be reported on Pepco’s state income tax returns and the amount
of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and
liabilities represent the tax effects of temporary differences between the
financial statement and tax basis of existing assets and liabilities and are
measured using presently enacted tax rates. The portion of Pepco’s deferred tax
liability applicable to its utility operations that has not been recovered from
utility customers represents income taxes recoverable in the future and is
included in “regulatory assets” on the Balance Sheets. See Note (6),
“Regulatory Assets and Regulatory Liabilities,” for additional
information.
Deferred income tax expense generally
represents the net change during the reporting period in the net deferred tax
liability and deferred recoverable income taxes.
Pepco recognizes interest on under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plants purchased in prior years are reported on the Balance Sheets as Investment
tax credits. These investment tax credits are being amortized to
income over the useful lives of the related utility plant.
FIN 46R, “Consolidation of
Variable Interest Entities”
Due to a variable element in the
pricing structure of Pepco’s purchase power agreement with Panda-Brandywine,
L.P. (Panda) entered into in 1991, pursuant to which Pepco was obligated to
purchase from Panda 230 megawatts of capacity and energy annually through 2021
(Panda PPA), Pepco potentially assumed the variability in the operations of the
plants related to the Panda PPA and therefore had a variable interest in the
entity.
During the third quarter of 2008, Pepco
transferred the Panda PPA to Sempra Energy Trading LLP. Net purchase activities
with the counterparty to the Panda PPA for the years ended December 31,2008, 2007 and 2006, were approximately $59 million, $85 million and $79
million, respectively. See Note (13), “Commitments and Contingencies —
Regulatory and Other Matters — Proceeds from Settlement of Mirant Bankruptcy
Claims,” for additional information.
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PEPCO
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, cash invested in money market funds, and commercial paper held with
original maturities of three months or less. Additionally, deposits
in PHI’s “money pool,” which Pepco and certain other PHI subsidiaries use to
manage short-term cash management requirements, are considered cash
equivalents. Deposits in the money pool are guaranteed by
PHI. PHI deposits funds in the money pool to the extent that the pool
has insufficient funds to meet the needs of its participants, which may require
PHI to borrow funds for deposit from external sources.
Restricted Cash
Equivalents
The restricted cash equivalents
included in Current Assets and the restricted cash equivalents included in
Investments and Other Assets represent (i) cash held as collateral that is
restricted from use for general corporate purposes and (ii) cash equivalents
that are specifically segregated, based on management’s intent to use such cash
equivalents. The classification as current or non-current conforms to the
classification of the related liabilities.
Accounts Receivable and
Allowance for Uncollectible Accounts
Pepco’s accounts receivable balance
primarily consists of customer accounts receivable, other accounts receivable,
and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned
in the current period but not billed to the customer until a future date
(usually within one month after the receivable is recorded).
Pepco
maintains an allowance for uncollectible accounts and changes in the allowance
are recorded as an adjustment to Other Operation and Maintenance expense in the
Statement of Earnings. Pepco determines the amount of the allowance based on
specific identification of material amounts at risk by customer and maintains a
general reserve based on its’ historical collection experience. The adequacy of
this allowance is assessed on a quarterly basis by evaluating all known factors
such as the aging of the receivables, historical collection experience, the
economic and competitive environment, and changes in the creditworthiness of its
customers. Although management believes its allowances is adequate, it cannot
anticipate with any certainty the changes in the financial condition of its
customers. As a result, Pepco records adjustments to the allowance for
uncollectible accounts in the period the new information is known.
Inventories
Included
in inventories are generation, transmission, and distribution materials and
supplies.
Pepco
utilizes the weighted average cost method of accounting for inventory items.
Under this method, an average price is determined for the quantity of units
acquired at each price level and is applied to the ending quantity to calculate
the total ending inventory balance. Materials and supplies inventory are
generally charged to inventory when purchased and then expensed or capitalized
to plant, as appropriate, when installed.
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PEPCO
Regulatory Assets and
Regulatory Liabilities
Pepco is regulated by the MPSC and the
District of Columbia Public Service Commission (DCPSC). The
transmission and wholesale sale of electricity by Pepco is regulated by the
Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in
which it has operated, Pepco has historically applied, and in connection with
its transmission and distribution business continues to apply, the provisions of
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS
No. 71 allows regulated entities, in appropriate circumstances, to establish
regulatory assets and to defer the income statement impact of certain costs that
are expected to be recovered in future rates. Management’s assessment
of the probability of recovery of regulatory assets requires judgment and
interpretation of laws, regulatory commission orders, and other
factors. If management subsequently determines, based on changes in
facts or circumstances that a regulatory asset is not probable of recovery, the
regulatory asset will be eliminated through a charge to earnings.
As part of the new electric service
distribution base rates for Pepco approved by the MPSC, effective in June 2007,
the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail
customers. For customers to which the BSA applies, Pepco recognizes distribution
revenue based on an approved distribution charge per customer. From a
revenue recognition standpoint, the BSA thus decouples the distribution revenue
recognized in a reporting period from the amount of power delivered during the
period. Pursuant to this mechanism, Pepco recognizes either (a) a
positive adjustment equal to the amount by which revenue from Maryland retail
distribution sales falls short of the revenue that Pepco is entitled to earn
based on the approved distribution charge per customer, or (b) a negative
adjustment equal to the amount by which revenue from such distribution sales
exceeds the revenue that Pepco is entitled to earn based on the approved
distribution charge per customer (a Revenue Decoupling Adjustment). A
positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a
negative Revenue Decoupling Adjustment is recorded as a regulatory
liability. The net Revenue Decoupling Adjustment at December 31, 2008
is a regulatory asset and is included in the “Other” line item on the table of
regulatory asset balances in Note (6), “Regulatory Assets and Regulatory
Liabilities.”
Investment in
Trust
Represents assets held in a trust for
the benefit of participants in the Pepco Owned Life Insurance plan.
Property, Plant and
Equipment
Property, plant and equipment are
recorded at original cost, including labor, materials, asset retirement costs
and other direct and indirect costs including capitalized
interest. The carrying value of property, plant and equipment is
evaluated for impairment whenever circumstances indicate the carrying value of
those assets may not be recoverable under the provisions of SFAS No.
144. Upon retirement, the cost of regulated property, net of salvage,
is charged to accumulated depreciation. For additional information
regarding the treatment of removal obligations, see the “Asset Retirement
Obligations” section included in this Note.
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PEPCO
The annual provision for depreciation
on electric property, plant and equipment is computed on the straight-line basis
using composite rates by classes of depreciable property. Accumulated
depreciation is charged with the cost of depreciable property retired, less
salvage and other recoveries. Property, plant and equipment other
than electric facilities is generally depreciated on a straight-line basis over
the useful lives of the assets. The system-wide composite
depreciation rates for 2008, 2007, and 2006 for Pepco’s transmission and
distribution system property were approximately 3%, 3%, and 4%,
respectively.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Statements of Earnings.
Pepco recorded AFUDC for borrowed funds
of $2 million, $5 million, and $1 million for the years ended December 31,2008, 2007, and 2006, respectively.
Pepco recorded amounts for the equity
component of AFUDC of $3 million for each of the years ended December 31, 2008
and 2007, and $2 million for the year ended December 31, 2006.
Leasing
Activities
Pepco’s
lease transactions can include office space, equipment, software and
vehicles. In accordance with SFAS No. 13, “Accounting for Leases”
(SFAS No. 13), these leases are classified as either capital leases or
operating leases.
Operating
Leases
An
operating lease generally results in a level income statement charge over the
term of the lease, reflecting the rental payments required by the lease
agreement. If rental payments are not made on a straight-line basis,
Pepco’s policy is to recognize the increases on a straight-line basis over the
lease term unless another systematic and rational allocation basis is more
representative of the time pattern in which the leased property is physically
employed.
Capital
Leases
For
ratemaking purposes capital leases are treated as operating leases; therefore,
in accordance with SFAS No. 71, the amortization of the leased asset is
based on the rental payments recovered from customers. Investments in equipment
under capital leases are stated at cost, less accumulated depreciation.
Depreciation is recorded on a straight-line basis over the equipment’s estimated
useful life.
Amortization of Debt
Issuance and Reacquisition Costs
Pepco defers and amortizes debt
issuance costs and long-term debt premiums and discounts over the lives of the
respective debt issues. Costs associated with the redemption of debt
are also deferred and amortized over the lives of the new
issues.
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PEPCO
Asset Removal
Costs
In accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations,” asset removal costs are
recorded as regulatory liabilities. At December 31, 2008 and 2007, $107
million and $98 million, respectively, are reflected as regulatory liabilities
in the accompanying Balance Sheets.
Pension and Other
Postretirement Benefit Plans
Pepco
Holdings sponsors a non-contributory retirement plan that covers substantially
all employees of Pepco (the PHI Retirement Plan) and certain employees of other
Pepco Holdings subsidiaries. Pepco Holdings also provides
supplemental retirement benefits to certain eligible executives and key
employees through nonqualified retirement plans and provides certain
postretirement health care and life insurance benefits for eligible retired
employees.
The PHI
Retirement Plan is accounted for in accordance with SFAS No. 87,
“Employers’ Accounting for Pensions,” as amended by SFAS No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158), and its
other postretirement benefits in accordance with SFAS No. 106, “Employers’
Accounting for Postretirement Benefits Other Than Pensions,” as amended by SFAS
No. 158. Pepco Holdings’ financial statement disclosures were
prepared in accordance with SFAS No. 132, “Employers’ Disclosures about Pensions
and Other Postretirement Benefits,” as amended by SFAS No. 158.
Pepco
participates in benefit plans sponsored by Pepco Holdings and as such, the
provisions of SFAS No. 158 do not have an impact on its financial condition and
cash flows.
Dividend
Restrictions
In addition to its future financial
performance, the ability of Pepco to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory laws, may
require the prior approval of Pepco’s utility regulatory commissions before
dividends can be paid and (ii) the prior rights of holders of future preferred
stock, if any, and existing and future mortgage bonds and other long-term debt
issued by Pepco and any other restrictions imposed in connection with the
incurrence of liabilities. Pepco has no shares of preferred stock
outstanding. Pepco had approximately $125 million and $75 million of
restricted retained earnings at December 31, 2008 and 2007,
respectively.
Reclassifications and
Adjustments
Certain prior year amounts have been
reclassified in order to conform to current year presentation.
During
2008, Pepco recorded adjustments to correct errors in Other Operation and
Maintenance expenses for prior periods dating back to February 2005 during which
(i) customer late payment fees were incorrectly recognized and (ii) stock-based
compensation expense related to certain restricted stock awards granted under
the Long-Term Incentive Plan was understated. These adjustments, which were not
considered material either individually or in the aggregate,
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PEPCO
resulted
in a total increase in Other Operation and Maintenance expenses of $6 million
for the year ended December 31, 2008, all of which related to prior
periods.
(3) NEWLY ADOPTED ACCOUNTING
STANDARDS
Statement of Financial Accounting
Standards (SFAS) No. 157, “Fair Value Measurements”
(SFAS No.
157)
SFAS No. 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies to
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. Under SFAS No.
157, fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants in
the most advantageous market using the best available information. The
provisions of SFAS No. 157 were effective for financial statements beginning
January 1, 2008 for Pepco.
In
February 2008, the FASB issued FSP 157-1, “Application of FASB Statement
No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That
Address Fair Value Measurements for Purposes of Lease Classification or
Measurement under Statement 13” (FSP 157-1), that removed fair value measurement
for the recognition and measurement of lease transactions from the scope of SFAS
No. 157. The effective date of FSP 157-1 was for financial statement
periods beginning January 1, 2008 for Pepco.
Also in
February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement
No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all
non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually), until financial statement reporting periods
beginning January 1, 2009 for Pepco.
Pepco applied the guidance of FSP No.
157-1 and FSP 157-2 with its adoption of SFAS No. 157. The adoption
of SFAS 157 on January 1, 2008 did not result in a transition adjustment to
beginning retained earnings and did not have a material impact on Pepco’s
overall financial condition, results of operations, or cash
flows. SFAS No. 157 also required new disclosures regarding the level
of pricing observability associated with financial instruments carried at fair
value. This additional disclosure is provided in Note (12), “Fair
Value Disclosures.” Pepco is currently evaluating the impact of FSP
157-2 and does not anticipate that the application of FSP 157-2 to its other
non-financial assets and non-financial liabilities will materially affect its
overall financial condition, results of operations, or cash flows.
In September 2008, the Securities
and Exchange Commission and FASB issued guidance on fair value measurements,
which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining
the Fair Value of a Financial Asset When the Market for that Asset is Not
Active.” This guidance clarifies the application of SFAS No. 157 to
assets in an inactive market and illustrates how to determine the fair value of
a financial asset in an inactive market. The guidance was effective beginning
with the September 30, 2008 reporting period for Pepco, and has not had a
material impact on Pepco’s results.
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SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities—including an Amendment of FASB Statement No.
115” (SFAS No.
159)
SFAS No. 159 permits entities to elect
to measure eligible financial instruments at fair value. SFAS No. 159
applies to other accounting pronouncements that require or permit fair value
measurements and does not require any new fair value measurements. On
January 1, 2008, Pepco elected not to apply the fair value option for its
eligible financial assets and liabilities.
SFAS No. 162, “The Hierarchy of
Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS
No. 162, which identifies the sources of accounting principles and the hierarchy
for selecting the principles to be used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with
GAAP. Moving the GAAP hierarchy into the accounting literature directs the
responsibility for applying the hierarchy to the reporting entity, rather than
just to the auditors.
SFAS No. 162 was effective for
Pepco as of November 15, 2008 and did not result in a change in accounting
for Pepco. Therefore, the provisions of SFAS No. 162 did not
have a material impact on Pepco’s overall financial condition, results of
operations, cash flows and disclosure.
FSP
FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain
Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued
FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that
provide credit protection through credit derivatives (including embedded credit
derivatives) within the scope of SFAS No. 133, and guarantees within the scope
of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others.”
For
credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature
and fair value of the credit derivative, the approximate term, the reasons for
entering the derivative, the events requiring performance, and the current
status of the payment/performance risk. It also requires disclosures
of the maximum potential amount of future payments without any reduction for
possible recoveries under collateral provisions, recourse provisions, or
liquidation proceeds. Pepco has not provided credit protection to
others through the credit derivatives within the scope of SFAS No.
133.
For
guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status
of the payment/performance risk and whether the current status is based on
external credit ratings or current internal groupings used to manage
risk. If internal groupings are used, then information is required
about how the groupings are determined and used for managing risk.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2008 for Pepco. Comparative disclosures are
only required for periods ending
after initial adoption. The new guarantee disclosures did not have a
material impact on Pepco.
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PEPCO
FSP
FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about
Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP
FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP
FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original
pronouncements. The disclosure requirements in SFAS No. 140 for transfers
of financial assets are to include disclosure of (i) a transferor’s continuing
involvement in transferred financial assets, and (ii) how a transfer of
financial assets to a special-purpose entity affects an entity’s financial
position, financial performance, and cash flows. The principal objectives of the
disclosure requirements in Interpretation 46(R) are to outline (i) significant
judgments in determining whether an entity should consolidate a variable
interest entity (VIE), (ii) the nature of any restrictions on consolidated
assets, (iii) the risks associated with the involvement in the VIE, and (iv) how
the involvement with the VIE affects an entity’s financial position, financial
performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is
effective for Pepco’s December 31, 2008 financial statements. This
FSP has no material impact to Pepco’s overall financial condition, results of
operations, or cash flows as it relates to SFAS No. 140. Pepco’s
FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies
- FIN 46R, Consolidation of Variable Interest Entities.”
(4) RECENTLY ISSUED ACCOUNTING
STANDARDS, NOT YET ADOPTED
SFAS No. 141(R) replaces FASB Statement
No. 141, “Business Combinations,” and retains the fundamental requirements that
the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business
combination. However, SFAS No. 141 (R) expands the definition of a
business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer
to recognize changes in the amount of its deferred tax benefits that are
realizable because of a business combination either in income from continuing
operations or directly in contributed capital, depending on the
circumstances.
In
January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and
Liabilities Assumed in a Business Combination that Arise from Contingencies”
(FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and
liabilities arising from contingencies in a business combination. The
FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a
business combination that arise from contingences be measured at fair value in
accordance with SFAS No. 157 if the acquisition date can be reasonably
determined. If not, then the asset or liability would be measured at
the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN
14, “Reasonable Estimate of the Amount of Loss.”
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PEPCO
SFAS No. 141(R) and the guidance
provided in FSP FAS 141(R)-a applies prospectively to business combinations for
which the acquisition date is on or after January 1, 2009 for
Pepco. Pepco has evaluated the impact of SFAS No. 141(R) and
does not anticipate its adoption will have a material impact on its overall
financial condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No.
160)
SFAS No. 160 establishes new accounting
and reporting standards for a non-controlling interest (also called a “minority
interest”) in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a minority interest in a subsidiary is
an ownership interest in the consolidated entity that should be separately
reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and
reporting standards that require (i) the ownership interests and the related
consolidated net income in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, and
presented separately on the face of the consolidated statement of
income, (ii) the changes in a parent’s ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for as
equity transactions, and (iii) when a subsidiary is deconsolidated, any retained
non-controlling equity investment in the former subsidiary must be initially
measured at fair value.
SFAS No. 160 is effective prospectively
for financial statement reporting periods beginning January 1, 2009 for
Pepco, except for the presentation and disclosure requirements. The
presentation and disclosure requirements apply retrospectively for all periods
presented. Pepco has evaluated the impact of SFAS No. 160
and does not anticipate its adoption will have a material impact on its overall
financial condition, results of operations, cash flows or
disclosure.
In November 2008, the FASB issued EITF
08-6 to address the accounting for equity method investments including: (i) how
an equity method investment should initially be measured, (ii) how it should be
tested for impairment, and (iii) how an equity method investee’s issuance of
shares should be accounted for. The EITF concludes that initial carrying value
of an equity method investment can be determined using the accumulation model in
SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary
impairments should be recognized in accordance with paragraph 19(h) of
Accounting Principles Board Opinion No. 18, “The Equity Method of
Accounting for Investments in Common Stock.”
This EITF
is effective for Pepco beginning January 1, 2009. Pepco is currently
evaluating the impact on its accounting and disclosures.
FSP
FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP FAS 132(R)-1)
In
December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. The required disclosures under this FSP would
expand current disclosures under SFAS No.
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PEPCO
132(R),
“Employers’ Disclosures about Pensions and Other Postretirement Benefits—an
amendment of FASB Statements No. 87, 88, and 106,” to be in line with SFAS
No. 157 required disclosures.
The
disclosures are to provide users an understanding of the investment allocation
decisions made, factors used in the investment policies and strategies, plan
assets by major investment types, inputs and valuation techniques used to
measure fair value of plan assets, significant concentration of risk within the
plan, and the effects of fair value measurement using significant unobservable
inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for
the period.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2009 for Pepco and earlier application is
permitted. Comparative disclosures under this provision are not
required for earlier periods presented. Pepco is currently evaluating
the impact on its disclosures.
(5) SEGMENT
INFORMATION
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” Pepco has
one segment, its regulated utility business.
(6) REGULATORY ASSETS AND
REGULATORY LIABILITIES
The components of Pepco’s regulatory
asset balances at December 31, 2008 and 2007 are as follows:
2008
2007
(Millions
of dollars)
Deferred
energy supply costs
$ 12
$ 15
Deferred
income taxes
53
61
Deferred
debt extinguishment costs
39
40
Other
65
63
Total
Regulatory Assets
$169
$179
The
components of Pepco’s regulatory liability balances at December 31, 2008
and 2007 are as follows:
2008
2007
(Millions
of dollars)
Deferred
energy supply cost
$ 9
$ 6
Deferred
income taxes due to customers
18
21
Asset
removal costs
107
98
Settlement
proceeds - Mirant bankruptcy claims
102
415
Other
2
2
Total
Regulatory Liabilities
$238
$542
A
description of the regulatory assets and regulatory liabilities is as
follows:
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PEPCO
Deferred Energy Supply Costs:
The regulatory asset primarily represents deferred costs associated with
a net under-recovery of Default Electricity Supply costs in
Maryland. The regulatory liability primarily represents deferred
costs associated with a net over-recovery of Default Electricity Supply costs
incurred in the District of Columbia. The Default Electricity Supply
deferrals do not earn a return.
Deferred Income Taxes: Represents a receivable
from our customers for tax benefits Pepco has previously flowed through before
the company was ordered to provide deferred income taxes. As the
temporary differences between the financial statement and tax basis of assets
reverse, the deferred recoverable balances are reversed. There is no
return on these deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and, if
approved, will be amortized to interest expense during the authorized rate
recovery period. A return is received on these
deferrals.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
Deferred Income Taxes Due to
Customers: Represents the portion of deferred income tax
liabilities applicable to Pepco’s utility operations that has not been reflected
in current customer rates for which future payment to customers is
probable. As temporary differences between the financial statement
and tax basis of assets reverse, deferred recoverable income taxes are
amortized. There is no return on these deferrals.
Asset Removal
Costs: Pepco’s depreciation rates include a component for
removal costs, as approved by its federal and state regulatory
commissions. Pepco has recorded a regulatory liability for their
estimate of the difference between incurred removal costs and the level of
removal costs recovered through rates.
Settlement proceeds - Mirant
Bankruptcy Claims: In 2007, Pepco received $414 million
of net proceeds from settlement of a Mirant Corporation (Mirant) claim, plus
interest earned, which was designated to pay for future above-market capacity
and energy purchases under the Panda PPA. In 2008, Pepco transferred
the Panda PPA to Sempra Energy Trading LLC (Sempra) in a transaction in which
Pepco made a payment to Sempra and all further Pepco rights, obligations and
liabilities under the Panda PPA were terminated. The balance at
December 31, 2008 reflects the funds remaining after the Sempra
payment. Pepco filed rate applications with the DCPSC and the MPSC in
the fourth quarter of 2008 to provide for the disposition of the remaining
funds. See Note (13), “Commitments and Contingencies — Proceeds From
Settlement of Mirant Bankruptcy Claims” for additional
information. Currently there is no return on these
deferrals.
Other: Includes
miscellaneous regulatory liabilities such as the over-recovery of administrative
costs associated with Maryland and District of Columbia SOS. These
regulatory liabilities generally do not receive a return.
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PEPCO
(7) LEASING
ACTIVITIES
Lease
Commitments
Pepco leases its consolidated control
center, which is an integrated energy management center used by Pepco to
centrally control the operation of its transmission and distribution
systems. This lease is accounted for as a capital lease and was
initially recorded at the present value of future lease payments, which totaled
$152 million. The lease requires semi-annual payments of $8 million
over a 25-year period beginning in December 1994 and provides for transfer of
ownership of the system to Pepco for $1 at the end of the lease
term. Under SFAS No. 71, the amortization of leased assets is
modified so that the total interest expense charged on the obligation and
amortization expense of the leased asset is equal to the rental expense allowed
for rate-making purposes. This lease has been treated as an operating
lease for rate-making purposes.
Capital lease assets recorded within
Property, Plant and Equipment at December 31, 2008 and 2007 are comprised
of the following:
The approximate annual commitments
under capital leases are $15 million for each year 2009 through 2013 and $92
million thereafter.
Rental expense for operating leases was
$4 million for each of the years ended December 31, 2008, 2007 and
2006.
Total future minimum operating lease
payments for Pepco as of December 31, 2008 are $3 million in 2009, $8 million in
2010, less than $1 million in each of the years 2011 through 2013, and $2
million after 2013.
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PEPCO
(8) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
The non-operating and other property
amounts include balances for general plant, distribution and transmission plant
held for future use, intangible plant and non-utility property.
(9) PENSIONS
AND OTHER POSTRETIREMENT BENEFITS
Pepco accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2008, 2007, and 2006, Pepco was responsible for $24
million, $22 million and $32 million, respectively, of the pension and other
postretirement net periodic benefit cost incurred by Pepco
Holdings. In 2008 and 2007, Pepco made no contributions to the PHI
Retirement Plan, and $9 million and $10 million, respectively to other
postretirement benefit plans. At December 31, 2008 and 2007, Pepco’s
prepaid pension expense of $142 million and $152 million, and other
postretirement benefit obligation of $49 million and $58 million,
effectively represent assets and benefit obligations resulting from Pepco’s
participation in the Pepco Holdings benefit plan. Pepco expects to
contribute approximately $170 million to the pension plan in 2009.
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PEPCO
(10) DEBT
LONG-TERM
DEBT
The components of long-term debt are
shown below.
At
December 31,
Interest Rate
Maturity
2008
2007
(Millions
of dollars)
First
Mortgage Bonds
6.50%
2008
$
-
$
78
5.875%
2008
-
50
5.75%
(a)
2010
16
16
4.95%
(a)(b)
2013
200
200
4.65%
(a)(b)
2014
175
175
Variable
(a)(b)(c)
2022
-
110
5.375%
(a)
2024
38
38
5.75%
(a)(b)
2034
100
100
5.40%
(a)(b)
2035
175
175
6.50%
(a)(b)
2037
500
250
7.90%
2038
250
-
Total
First Mortgage Bonds
1,454
1,192
Medium-Term
Notes
6.25%
2009
50
50
Total
long-term debt
1,504
1,242
Net
unamortized discount
(9)
(2)
Current
maturities of long-term debt
(50)
(128)
Total
net long-term debt
$
1,445
$
1,112
(a)
Represents
a series of First Mortgage Bonds issued by Pepco as collateral for an
outstanding series of senior notes issued by the company or tax-exempt
bonds issued by or for the benefit of Pepco. The maturity date,
optional and mandatory prepayment provisions, if any, interest rate, and
interest payment dates on each series of senior notes or the obligations
in respect of the tax-exempt bonds are identical to the terms of the
corresponding series of collateral First Mortgage
Bonds. Payments of principal and interest on a series of senior
notes or the company’s obligations in respect of the tax-exempt bonds
satisfy the corresponding payment obligations on the related series of
collateral First Mortgage Bonds. Because each series of senior
notes and tax-exempt bonds and the corresponding series of collateral
First Mortgage Bonds securing that series of senior notes or tax-exempt
bonds effectively represents a single financial obligation, the senior
notes and the tax-exempt bonds are not separately shown on the
table.
(b)
Represents
a series of First Mortgage Bonds issued by Pepco as collateral for an
outstanding series of senior notes as described in footnote (a) above that
will, at such time as there are no First Mortgage Bonds of Pepco
outstanding (other than collateral First Mortgage Bonds securing payment
of senior notes), cease to secure the corresponding series of senior notes
and will be cancelled.
(c)
The
insured auction rate tax exempt bonds were repurchased by Pepco at par due
to the disruption in the credit markets. The bonds are considered
extinguished for accounting purposes however Pepco intends to remarket or
reissue the bonds to the public in
2009.
The outstanding First Mortgage Bonds
are subject to a lien on substantially all of Pepco’s property, plant and
equipment.
The aggregate principal amount of
long-term debt outstanding at December 31, 2008, that will mature in each
of 2009 through 2013 and thereafter is as follows: $50 million in
2009, $16 million in 2010, zero in 2011 and 2012, $200 million in 2013, and
$1,238 million thereafter.
Pepco’s long-term debt is subject to
certain covenants. Pepco is in compliance with all
requirements.
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PEPCO
SHORT-TERM
DEBT
Pepco, a regulated utility, has
traditionally used a number of sources to fulfill short-term funding needs, such
as commercial paper, short-term notes, and bank lines of credit. Proceeds from
short-term borrowings are used primarily to meet working capital needs, but may
also be used to temporarily fund long-term capital requirements. A
detail of the components of Pepco’s short-term debt at December 31, 2008 and
2007 is as follows.
2008
2007
(Millions
of dollars)
Commercial
paper
$ -
$ 84
Intercompany
borrowings
-
96
Bank
Loan
25
-
Credit
Facility Loans
100
-
Total
$125
$180
Commercial
Paper
Pepco maintains an ongoing commercial
paper program of up to $500 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with PHI’s other utility subsidiaries,
Delmarva Power & Light Company (DPL) and Atlantic City Electric Company
(ACE).
Pepco had no commercial paper
outstanding at December 31, 2008 and $84 million of commercial paper outstanding
at December 31, 2007. The weighted average interest rate for commercial paper
issued during 2008 was 3.45% and 5.27% in 2007. The weighted average
maturity for commercial paper issued during 2008 was two days and during 2007
was four days.
Bank
Loan
In May
2008, Pepco obtained a $25 million bank loan that matures on April 30,2009. Interest on the loan is calculated at a variable
rate.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under this primary credit
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is, at the borrowing company’s election, (i) the greater of the
prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the
prevailing Eurodollar rate, plus a margin that varies according to the credit
rating of the borrower. The facility also includes a “swingline loan
sub-facility,” pursuant to which each company may make same day borrowings in an
aggregate amount not to exceed $150 million.
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PEPCO
Any
swingline loan must be repaid by the borrower within seven days of receipt
thereof. All indebtedness incurred under the facility is
unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties must be true, and the borrower must be in
compliance with specified covenants, including (i) the requirement that
each borrowing company maintain a ratio of total indebtedness to total
capitalization of 65% or less, computed in accordance with the terms of the
credit agreement, which calculation excludes from the definition of total
indebtedness certain trust preferred securities and deferrable interest
subordinated debt (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than certain sales
and dispositions, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other than permitted
liens. The absence of a material adverse change in the borrower’s
business, property, and results of operations or financial condition is not a
condition to the availability of credit under the facility. The facility does
not include any rating triggers.
As a
result of severe liquidity constraints in the credit, commercial paper and
capital markets during 2008, Pepco borrowed under the $1.5 billion credit
facility. Typically, Pepco issues commercial paper if required to
meet its short-term working capital requirements. Given the lack of
liquidity in the commercial paper markets, Pepco borrowed under the credit
facility to maintain sufficient cash on hand to meet daily short-term operating
needs. At December 31, 2008, Pepco had borrowed $100 million. The LIBOR-based
loan matures in April 2009.
(11) INCOME
TAXES
Pepco, as a direct subsidiary of PHI,
is included in the consolidated federal income tax return of
PHI. Federal income taxes are allocated to Pepco pursuant to a
written tax sharing agreement that was approved by the Securities and Exchange
Commission in connection with the establishment of PHI as a holding company as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for income taxes,
reconciliation of income tax expense, and components of deferred income tax
liabilities (assets) are shown below.
During
2008, Pepco completed an analysis of its current and deferred income tax
accounts and, as a result, recorded a $3 million net credit to income tax
expense in 2008, which is primarily included in “Deferred tax adjustments” in
the reconciliation provided above. In addition, during 2008 Pepco
recorded after-tax net interest income of $5 million under FIN 48 primarily
related to the reversal of previously accrued interest payable resulting from a
favorable tentative settlement of the Mixed Service Cost issue with the IRS and
after-tax interest income of $2 million for interest received in 2008 on the
Maryland state tax refund.
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PEPCO
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant
Accounting Policies,” Pepco adopted FIN 48 effective January 1,2007. Upon adoption, Pepco recorded the cumulative effect of the
change in accounting principle of $2 million as a decrease in retained
earnings. Also upon adoption, Pepco had $95 million of unrecognized
tax benefits and $7 million of related accrued interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
2008
2007
Beginning
balance as of January 1,
$
60
$
95
Tax
positions related to current year:
Additions
1
2
Tax
positions related to prior years:
Additions
38
4
Reductions
(37)
(8)
Settlements
-
(33)
Ending
balance as of December 31,
$
62
$
60
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits related to tax positions that have been taken or are expected
to be taken in tax returns that are not recognized in the financial statements
because, in accordance with FIN 48, management has either measured the tax
benefit at an amount less than the benefit claimed, or expected to be claimed,
or has concluded that it is not more likely than not that the tax position will
be ultimately sustained.
For the majority of these tax
positions, the ultimate deductibility is highly certain, but there is
uncertainty about the timing of such deductibility. At December 31,2008, Pepco had no unrecognized tax benefits that, if recognized, would lower
the effective tax rate.
Interest and Penalties
Pepco recognizes interest and penalties
relating to its uncertain tax positions as an element of income tax
expense. For the years ended December 31, 2008 and 2007, Pepco
recognized $8 million of interest income before tax ($5 million after-tax) and
$1 million of interest income before tax (less than $1 million after-tax),
respectively, as a component of income tax expense. As of December31, 2008 and 2007, Pepco had $4 million and $9 million, respectively, of accrued
interest payable related to effectively settled and uncertain tax
positions.
Possible Changes to Unrecognized Tax
Benefits
It is reasonably possible that the
amount of the unrecognized tax benefit with respect to certain of Pepco’s
unrecognized tax positions will significantly increase or decrease within the
next 12 months. The final settlement of the Mixed Service Cost issue or
other federal or state audits could impact the balances significantly. At this
time, other than the Mixed Service Cost issue, an estimate of the range of
reasonably possible outcomes cannot be determined. The unrecognized benefit
related to the Mixed Service Cost issue could decrease by
$20 million
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PEPCO
within
the next 12 months upon final resolution of the tentative settlement with
the IRS and the obligation becomes certain. See Note (13),
“Commitments and Contingencies,” herein for additional information.
Tax Years Open to
Examination
Pepco, as a direct subsidiary of PHI,
is included on PHI’s consolidated federal income tax return. Pepco’s
federal income tax liabilities for all years through 2000 have been determined,
subject to adjustment to the extent of any net operating loss or other loss or
credit carrybacks from subsequent years. The open tax years for the
significant states where Pepco files state income tax returns (District of
Columbia and Maryland) are the same as noted above.
Components of Deferred
Income Tax Liabilities (Assets)
Depreciation
and other basis differences related to plant and equipment
$
682
$
616
Pension
and other postretirement benefits
99
26
Deferred
taxes on amounts to be collected through future rates
19
12
Other
(21)
(38)
Total
Deferred Tax Liabilities, Net
779
616
Deferred
tax assets included in Other Current Assets
8
3
Deferred
tax assets included in Other Current Liabilities
1
-
Total
Deferred Tax Liabilities, Net - Non-Current
$
788
$
619
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement and tax basis of assets and
liabilities. The portion of the net deferred tax liability
applicable to Pepco’s operations, which has not been reflected in current
service rates, represents income taxes recoverable through future rates, net and
is recorded as a regulatory asset on the balance sheet. No valuation
allowance for deferred tax assets was required or recorded at December 31, 2008
and 2007.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously earned
on Pepco’s property continues to be normalized over the remaining service lives
of the related assets.
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Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
2008
2007
2006
(Millions
of dollars)
Gross
Receipts/Delivery
$106
$108
$109
Property
38
36
35
County
Fuel and Energy
90
88
84
Environmental,
Use and Other
54
58
45
Total
$288
$290
$273
(12) FAIR VALUE
DISCLOSURES
Effective
January 1, 2008, Pepco adopted SFAS No. 157, as discussed earlier in
Note (3), which established a framework for measuring fair value and
expands disclosures about fair value measurements.
As defined in SFAS No. 157, fair value
is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date (exit price). Pepco utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. Accordingly, Pepco
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. Pepco is able to classify
fair value balances based on the observability of those inputs. SFAS
No. 157 establishes a fair value hierarchy that prioritizes the inputs used to
measure fair value. The hierarchy gives the highest priority to
unadjusted quoted prices in active markets for identical assets or liabilities
(level 1 measurement) and the lowest priority to unobservable inputs (level 3
measurement). The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:
Level 1 — Quoted prices are available
in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
Level 2 — Pricing inputs are other than
quoted prices in active markets included in level 1, which are either directly
or indirectly observable as of the reporting date. Level 2 includes
those financial instruments that are valued using broker quotes in liquid
markets, and other observable pricing data. Level 2 also includes
those financial instruments that are valued using internally developed
methodologies that have been corroborated by observable market data through
correlation or by other means. Significant assumptions are observable
in the marketplace throughout the full term of the instrument, can be derived
from observable data or are supported by observable levels at which transactions
are executed in the marketplace.
Level 3 — Pricing inputs include
significant inputs that are generally less observable than those from objective
sources. Level 3 includes those financial investments that are valued
using
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models or
other valuation methodologies. Level 3 instruments classified as executive
deferred compensation plan assets are life insurance policies that are valued
using the cash surrender value of the policies. Since these values do not
represent a quoted price in an active market they are considered Level
3.
The following table sets forth by level
within the fair value hierarchy Pepco’s financial assets and liabilities that
were accounted for at fair value on a recurring basis as of December 31,2008. As required by SFAS No. 157, financial assets and liabilities
are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. Pepco’s assessment of the
significance of a particular input to the fair value measurement requires the
exercise of judgment, and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy
levels.
Quoted
Prices in Active Markets for Identical Instruments (Level
1)
Significant
Other Observable Inputs (Level 2)
Significant
Unobservable Inputs
(Level
3)
ASSETS
Cash
equivalents
$
236
$
236
$
-
$
-
Executive
deferred
compensation
plan assets
59
7
35
17
$
295
$
243
$
35
$
17
LIABILITIES
Executive
deferred compensation plan liabilities
$
13
$
-
$
13
$
-
$
13
$
-
$
13
$
-
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A reconciliation of the beginning and
ending balances of Pepco’s fair value measurements using significant
unobservable inputs (level 3) is shown below (in millions of
dollars):
Gains
or (losses) (realized and unrealized) included in earnings for the period
above are reported in Other Operation and Maintenance Expense as
follows:
Other
Operation and Maintenance Expense
Total
gains included in earnings for the period above
$
4
Change
in unrealized gains relating to assets still
held
at reporting date
$
4
The estimated fair values of Pepco’s
non-financial instruments at December 31, 2008 and 2007 are shown
below.
The fair values of the Long-Term Debt,
which include First Mortgage Bonds and Medium-Term Notes, including amounts due
within one year, were based on the current market prices, or for issues with no
market price available, were based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.
(13) COMMITMENTS AND
CONTINGENCIES
REGULATORY
AND OTHER MATTERS
Proceeds
from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. As part of the sale,
Pepco and Mirant entered into a “back-to-back” arrangement, whereby Mirant
agreed
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to
purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was
obligated to purchase annually through 2021 from Panda under the Panda PPA at
the purchase price Pepco was obligated to pay to Panda. 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 settlement of Pepco’s claims against Mirant
arising from the 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 was obligated to pay Panda for the energy and capacity
exceeded the market price. In 2007, Pepco received as damages
$414 million in net proceeds from the sale of shares of Mirant common stock
issued to it by Mirant.
On September 5, 2008, Pepco
transferred the Panda PPA to Sempra Energy Trading LLC (Sempra), along with a
payment to Sempra, thereby terminating all further rights, obligations and
liabilities of Pepco under the Panda PPA. The use of the damages
received from Mirant to offset above-market costs of energy and capacity under
the Panda PPA and to make the payment to Sempra reduced the balance of proceeds
from the Mirant settlement to approximately $102 million as of December 31,2008.
In November 2008, Pepco filed with the
DCPSC and the MPSC proposals to share with customers the remaining balance of
proceeds from the Mirant settlement in accordance with divestiture sharing
formulas previously approved by the respective commissions. Under
Pepco’s proposals, District of Columbia and Maryland customers would receive a
total of approximately $25 million and $29 million,
respectively. On December 12, 2008, the DCPSC issued a Notice of
Proposed Rulemaking concerning the sharing of the Mirant divestiture proceeds,
including the bankruptcy settlement proceeds. The public comment
period for the proposed rules has expired without any comments being
submitted. This matter remains pending before the DCPSC.
On February 17, 2009, Pepco, the
Maryland Office of People’s Counsel (the Maryland OPC) and the MPSC staff filed
a settlement agreement with the MPSC. The settlement, among other
things, provides that of the remaining balance of the Mirant settlement, Pepco
shall distribute $39 million to its Maryland customers through a one-time
billing credit. If the settlement is approved by the MPSC, Pepco
currently estimates that it will result in a pre-tax gain in the range of $15
million to $20 million, which will be recorded when the MPSC issues its final
order approving the settlement.
Pending the final disposition of these
funds, the remaining $102 million in proceeds from the Mirant settlement is
being accounted for as restricted cash and as a regulatory
liability.
Rate
Proceedings
In the most recent electric service
distribution base rate cases filed by Pepco in the District of Columbia and
Maryland, Pepco proposed the adoption of a BSA for retail
customers. As more fully discussed below, the implementation of a BSA
has been approved for electric service in Maryland and remains pending in the
District of Columbia. Under the BSA, customer delivery rates are
subject to adjustment (through a surcharge or credit mechanism), depending on
whether actual distribution revenue per customer exceeds or falls short of the
approved revenue-per-customer amount. The BSA increases rates if
actual distribution revenues fall below the level approved by the applicable
commission and decreases rates if actual distribution revenues are above the
approved level. The result is that, over time, Pepco collects its
authorized revenues
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for
distribution deliveries. As a consequence, a BSA “decouples” revenue
from unit sales consumption and ties the growth in revenues to the growth in the
number of customers. Some advantages of the BSA are that it
(i) eliminates revenue fluctuations due to weather and changes in customer
usage patterns and, therefore, provides for more predictable utility
distribution revenues that are better aligned with costs, (ii) provides for
more reliable fixed-cost recovery, (iii) tends to stabilize customers’
delivery bills, and (iv) removes any disincentives for Pepco to promote
energy efficiency programs for its customers, because it breaks the link between
overall sales volumes and delivery revenues.
District of Columbia
In December 2006, Pepco submitted
an application to the DCPSC to increase electric distribution base rates,
including a proposed BSA. In January 2008, the DCPSC approved,
effective February 20, 2008, a revenue requirement increase of
approximately $28 million, based on an authorized return on rate base of
7.96%, including a 10% return on equity (ROE). This increase did not
include a BSA mechanism. While finding a BSA to be an appropriate
ratemaking concept, the DCPSC cited potential statutory problems in its
authority to implement the BSA. In February 2008, the DCPSC
established a Phase II proceeding to consider these implementation
issues. In August 2008, the DCPSC issued an order concluding that it
has the necessary statutory authority to implement the BSA proposal and that
further evidentiary proceedings are warranted to determine whether the BSA is
just and reasonable. On January 2, 2009, the DCPSC issued an order
designating the issues and establishing a procedural schedule for the BSA
proceeding. Hearings are scheduled for the second quarter of
2009.
In June 2008, the District of Columbia
Office of People’s Counsel (the DC OPC), citing alleged errors by the DCPSC,
filed with the DCPSC a motion for reconsideration of the January 2008 order
granting Pepco’s rate increase, which was denied by the DCPSC. In
August 2008, the DC OPC filed with the District of Columbia Court of Appeals a
petition for review of the DCPSC order denying its motion for
reconsideration. The District of Columbia Court of Appeals granted
the petition; briefs have been filed by the parties and oral argument is
scheduled for March 2009.
Maryland
In July 2007, the MPSC issued an
order in Pepco’s electric service distribution rate case, which included
approval of a BSA. The order approved an annual increase in
distribution rates of approximately $11 million (including a decrease in
annual depreciation expense of approximately $31 million). The
approved distribution rate reflects an ROE of 10%. The rate increases
were effective as of June 16, 2007, and remained in effect for an initial
period until July 19, 2008, pending a Phase II proceeding in which the MPSC
considered the results of an audit of Pepco’s cost allocation manual, as filed
with the MPSC, to determine whether a further adjustment to the rates was
required. On July 18, 2008, the MPSC issued an order covering
the Phase II proceedings, denying any further adjustment to Pepco’s rates, thus
making permanent the rate increases approved in the July 2007
order. The MPSC also issued an order on August 4, 2008, further
explaining its July 18 order.
Pepco has filed a general notice of
appeal of the MPSC July 2007 and the July 18 and August 4, 2008
orders. The appeal challenges the MPSC’s failure to implement
permanent rates in accordance with Maryland law, and seek judicial review of the
MPSC’s denial of Pepco’s
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rights to
recover an increased share of the PHI Service Company costs and the costs of
performing a MPSC-mandated management audit. The case currently is
pending before the Circuit Court for Baltimore City. Under the
procedural schedule set by the court, Pepco will file a consolidated brief on or
before March 9, 2009, specifying the basis for its requested
relief.
Federal Energy Regulatory
Commission
On August 18, 2008, Pepco submitted an
application with the Federal Energy Regulatory Commission (FERC) for incentive
rate treatments in connection with PHI’s 230-mile, 500-kilovolt Mid-Atlantic
Power Pathway Project (the MAPP Project). The application requested
that FERC include Pepco’s Construction Work in Progress in its transmission rate
base, an ROE adder of 150 basis points (for a total ROE of 12.8%) and the
recovery of prudently incurred costs in the event the project is abandoned or
terminated for reasons beyond Pepco’s control. On October 31,2008, FERC issued an order approving the application.
Divestiture
Cases
District of Columbia
In June 2000, the DCPSC approved a
divestiture settlement under which Pepco is required to share with its District
of Columbia customers the net proceeds realized by Pepco from the sale of its
generation-related assets. An unresolved issue relating to the
application filed with the DCPSC by Pepco to implement the divestiture
settlement is whether Pepco should be required to share with customers the
excess deferred income taxes (EDIT) and accumulated deferred investment tax
credits (ADITC) associated with the sold assets and, if so, whether such sharing
would violate the normalization provisions of the Internal Revenue Code and its
implementing regulations. As of December 31, 2008, the District
of Columbia allocated portions of EDIT and ADITC associated with the divested
generating assets were approximately $7 million and $6 million,
respectively. Other issues in the divestiture proceeding deal with
the treatment of internal costs and cost allocations as deductions from the
gross proceeds of the divestiture.
Pepco believes that a sharing of EDIT
and ADITC would violate the Internal Revenue Service (IRS) normalization
rules. Under these rules, Pepco could not transfer the EDIT and the
ADITC benefit to customers more quickly than on a straight line basis over the
book life of the related assets. Since the assets are no longer owned
by Pepco, there is no book life over which the EDIT and ADITC can be
returned. If Pepco were required to share EDIT and ADITC and, as a
result, the normalization rules were violated, Pepco would be unable to use
accelerated depreciation on District of Columbia allocated or assigned
property. In addition to sharing with customers the
generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS
an amount equal to Pepco’s District of Columbia jurisdictional
generation-related ADITC balance ($6 million as of December 31, 2008),
as well as its District of Columbia jurisdictional transmission and
distribution-related ADITC balance ($3 million as of December 31,2008) in each case as those balances exist as of the later of the date a DCPSC
order is issued and all rights to appeal have been exhausted or lapsed, or the
date the DCPSC order becomes operative.
In March 2008, the IRS approved final
regulations, effective March 20, 2008, which allow utilities whose assets
cease to be utility property (whether by disposition, deregulation or otherwise)
to return to its utility customers the normalization reserve for EDIT and part
or all of
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the
normalization reserve for ADITC. This ruling applies to assets
divested after December 21, 2005. For utility property divested
on or before December 21, 2005, the IRS stated that it would continue to
follow the holdings set forth in private letter rulings prohibiting the flow
through of EDIT and ADITC associated with the divested assets. Pepco
made a filing in April 2008, advising the DCPSC of the adoption of the final
regulations and requesting that the DCPSC issue an order consistent with the IRS
position. If the DCPSC issues the requested order, no accounting
adjustments to the gain recorded in 2000 would be required.
As part of the proposal filed with the
DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant
settlement, as discussed above under “Proceeds from Settlement of Mirant
Bankruptcy Claims,” Pepco again requested that the DCPSC rule on all of the
issues related to the divestiture of Pepco’s generating assets that remain
outstanding. On December 12, 2008, the DCPSC issued a Notice of
Proposed Rulemaking, which gave notice of Pepco’s November 2008 sharing of
proceeds filing and requested comments. The public comment period for
the proposed rules has expired without any comments being
submitted. This matter remains pending before the DCPSC.
Pepco believes that its calculation of
the District of Columbia customers’ share of divestiture proceeds is
correct. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to make additional gain-sharing payments to
District of Columbia customers, including the payments described above related
to EDIT and ADITC. Such additional payments (which, other than the
EDIT and ADITC related payments, cannot be estimated) would be charged to
expense in the quarter and year in which a final decision is rendered and could
have a material adverse effect on Pepco’s and PHI’s results of operations for
those periods. However, neither PHI nor Pepco believes that
additional gain-sharing payments, if any, or the ADITC-related payments to the
IRS, if required, would have a material adverse impact on its financial position
or cash flows.
Maryland
Pepco filed its divestiture proceeds
plan application with the MPSC in April 2001. The principal
issue in the Maryland case is the same EDIT and ADITC sharing issue that has
been raised in the District of Columbia case. See the discussion
above under “Divestiture Cases — District of Columbia.” As of
December 31, 2008, the Maryland allocated portions of EDIT and ADITC
associated with the divested generating assets were approximately
$9 million and $10 million, respectively. Other issues deal
with the treatment of certain costs as deductions from the gross proceeds of the
divestiture. In November 2003, the Hearing Examiner in the
Maryland proceeding issued a proposed order with respect to the application that
concluded that Pepco’s Maryland divestiture settlement agreement provided for a
sharing between Pepco and customers of the EDIT and ADITC associated with the
sold assets. Pepco believes that such a sharing would violate the
normalization rules (as discussed above) and would result in Pepco’s inability
to use accelerated depreciation on Maryland allocated or assigned
property. If the proposed order is affirmed, Pepco would have to
share with its Maryland customers, on an approximately 50/50 basis, the Maryland
allocated portion of the generation-related EDIT ($9 million as of
December 31, 2008), and the Maryland-allocated portion of
generation-related ADITC. Furthermore, Pepco would have to pay to the
IRS an amount equal to Pepco’s Maryland jurisdictional generation-related ADITC
balance ($10 million as of December 31, 2008), as well as its Maryland
retail jurisdictional ADITC transmission and distribution-related balance
($6 million as of December 31, 2008), in each case as those balances
exist as of the later
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of the
date a MPSC order is issued and all rights to appeal have been exhausted or
lapsed, or the date the MPSC order becomes operative. The Hearing
Examiner decided all other issues in favor of Pepco, except for the
determination that only one-half of the severance payments that Pepco included
in its calculation of corporate reorganization costs should be deducted from the
sales proceeds before sharing of the net gain between Pepco and
customers.
In December 2003, Pepco appealed
the Hearing Examiner’s decision to the MPSC as it relates to the treatment of
EDIT and ADITC and corporate reorganization costs. The MPSC has not
issued any ruling on the appeal, pending completion of the IRS rulemaking
regarding sharing of EDIT and ADITC related to divested assets. Pepco
made a filing in April 2008, advising the MPSC of the adoption of the final IRS
normalization regulations (described above under “Divestiture Cases — District
of Columbia”) and requesting that the MPSC issue a ruling on the appeal
consistent with the IRS position. If the MPSC issues the requested
ruling, no accounting adjustments to the gain recorded in 2000 would be
required. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to share with its customers approximately 50
percent of the EDIT and ADITC balances described above in addition to the
additional gain-sharing payments relating to the disallowed severance
payments. Such additional payments would be charged to expense in the
quarter and year in which a final decision is rendered and could have a material
adverse effect on Pepco’s and PHI’s results of operations for those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
As part of the proposal filed with the
MPSC in November 2008 concerning the sharing of the proceeds of the Mirant
settlement, as discussed above under “Proceeds from Settlement of Mirant
Bankruptcy Claims,” Pepco again requested that the MPSC rule on all of the
issues related to the divestiture of Pepco’s generating assets that remain
outstanding.
On February 17, 2009, Pepco, the
Maryland OPC and the MPSC staff filed a settlement agreement with the
MPSC. The settlement agreement, among other things, provides that
Pepco will be allowed to retain the EDIT and ADITC reserves associated with
Pepco’s divested generating assets and that none of those amounts will be
available for sharing with Pepco’s Maryland customers. The matter is
pending before the MPSC.
General
Litigation
In 1993, Pepco was served with Amended
Complaints filed in the state Circuit Courts of Prince George’s County,
Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated
proceedings known as “In re: Personal Injury Asbestos
Case.” Pepco and other corporate entities were brought into these
cases on a theory of premises liability. Under this theory, the
plaintiffs argued that Pepco was negligent in not providing a safe work
environment for employees or its contractors, who allegedly were exposed to
asbestos while working on Pepco’s property. Initially, a total of
approximately 448 individual plaintiffs added Pepco to their
complaints. While the pleadings are not entirely clear, it appears
that each plaintiff sought $2 million in compensatory damages and
$4 million in punitive damages from each defendant.
Since the initial filings in 1993,
additional individual suits have been filed against Pepco, and significant
numbers of cases have been dismissed. As a result of two motions to
dismiss, numerous hearings and meetings and one motion for summary judgment,
Pepco has had
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approximately
400 of these cases successfully dismissed with prejudice, either voluntarily by
the plaintiff or by the court. As of December 31, 2008, there
are approximately 180 cases still pending against Pepco in the State Courts of
Maryland, of which approximately 90 cases were filed after December 19,2000, and were tendered to Mirant for defense and indemnification pursuant to
the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant
under which Pepco sold its generation assets to Mirant in 2000.
While the aggregate amount of monetary
damages sought in the remaining suits (excluding those tendered to Mirant) is
approximately $360 million, Pepco believes the amounts claimed by the
remaining plaintiffs are greatly exaggerated. The amount of total
liability, if any, and any related insurance recovery cannot be determined at
this time; however, based on information and relevant circumstances known at
this time, Pepco does not believe these suits will have a material adverse
effect on its financial position, results of operations or cash
flows. However, if an unfavorable decision were rendered against
Pepco, it could have a material adverse effect on Pepco’s financial position,
results of operations or cash flows.
Environmental
Litigation
Pepco is subject to regulation by
various federal, regional, state, and local authorities with respect to the
environmental effects of its operations, including air and water quality
control, solid and hazardous waste disposal, and limitations on land
use. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. Pepco may incur costs to clean up
currently or formerly owned facilities or sites found to be contaminated, as
well as other facilities or sites that may have been contaminated due to past
disposal practices. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from Pepco’s customers,
environmental clean-up costs incurred by Pepco would be included in its cost of
service for ratemaking purposes.
Metal Bank/Cottman Avenue
Site. In the early 1970s, Pepco sold scrap transformers, some
of which may have contained some level of PCBs, to a metal reclaimer operating
at the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a
nonaffiliated company. In 1987, Pepco was notified by the United
States Environmental Protection Agency (EPA) that it, along with a number of
other utilities and non-utilities, was a potentially responsible party (PRP) in
connection with the PCB contamination at the site.
In 1997, the EPA issued a Record of
Decision that set forth a remedial action plan for the site with estimated
implementation costs of approximately $17 million. In May 2003,
two of the potentially liable owner/operator entities filed for reorganization
under Chapter 11 of the U.S. Bankruptcy Code. In October 2003, the
bankruptcy court confirmed a reorganization plan that incorporates the terms of
a settlement among the two debtor owner/operator entities, the United States and
a group of utility PRPs including Pepco (the Utility PRPs). Under the
bankruptcy settlement, the reorganized entity/site owner will pay a total of
approximately $13 million to remediate the site (the Bankruptcy
Settlement).
In March 2006, the U.S. District Court
for the Eastern District of Pennsylvania approved global consent decrees for the
Metal Bank/Cottman Avenue site, entered into on August 23, 2005, involving the
Utility PRPs, the U.S. Department of Justice, EPA, The City of Philadelphia and
two owner/operators of the site. Under the terms of the settlement,
the two owner/operators
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will make
payments totaling approximately $6 million to the U.S. Department of
Justice and totaling approximately $4 million to the Utility
PRPs. The Utility PRPs will perform the remedy at the site and will
be able to draw on the approximately $13 million from the Bankruptcy
Settlement to accomplish the remediation (the Bankruptcy Funds). The
Utility PRPs will contribute funds to the extent remediation costs exceed the
Bankruptcy Funds available. The Utility PRPs also will be liable for
EPA costs associated with overseeing the monitoring and operation of the site
remedy after the remedy construction is certified to be complete and also the
cost of performing the “5 year” review of site conditions required by the
Comprehensive Environmental Response, Compensation, and Liability Act of
1980. Any Bankruptcy Funds not spent on the remedy may be used to
cover the Utility PRPs’ liabilities for future costs. No parties are
released from potential liability for damages to natural resources.
As of December 31, 2008, Pepco had
accrued approximately $2 million to meet its liability for a remedy at the
Metal Bank/Cottman Avenue site. While final costs to Pepco of the
settlement have not been determined, Pepco believes that its liability at this
site will not have a material adverse effect on its financial position, results
of operations or cash flows.
IRS
Mixed Service Cost Issue
During
2001, Pepco changed its method of accounting with respect to capitalizable
construction costs for income tax purposes. The change allowed Pepco
to accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $94
million for Pepco, primarily attributable to Pepco’s 2001 tax
returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require Pepco
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on those proposed regulations, PHI in its 2005 federal
tax return adopted an alternative method of accounting for capitalizable
construction costs that management believed would be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which was
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that Pepco had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
U.S. Office of Appeals of the IRS.
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. In June 2008, PHI
received from the IRS an offer of settlement pertaining to Pepco for the tax
years 2001 through 2004. Pepco is substantially in agreement with
this proposed settlement. Based on the terms of the proposal, Pepco
expects the final settlement amount to be less than the $121 million previously
deposited.
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On the
basis of the tentative settlement, Pepco updated its estimated liability related
to mixed service costs and as a result, recorded in the quarter ended June 30,2008, a net reduction in its liability for unrecognized tax benefits of $16
million and recognized after-tax interest income of $3 million.
Contractual
Obligations
As of December 31, 2008, Pepco’s
contractual obligations under non-derivative fuel and power purchase contracts
were $1,202 million in 2009, $975 million in 2010 to 2011, $25 million in 2012
to 2013, and zero in 2014 and thereafter.
(14) RELATED PARTY
TRANSACTIONS
PHI Service Company provides various
administrative and professional services to PHI and its regulated and
unregulated subsidiaries including Pepco. The cost of these services
is allocated in accordance with cost allocation methodologies set forth in the
service agreement using a variety of factors, including the subsidiaries’ share
of employees, operating expenses, assets, and other cost causal
methods. These intercompany transactions are eliminated by PHI in
consolidation and no profit results from these transactions at
PHI. PHI Service Company costs directly charged or allocated to Pepco
for the years ended December 31, 2008, 2007 and 2006 were approximately $145
million, $129 million, and $114 million, respectively.
Certain subsidiaries of Pepco Energy
Services perform utility maintenance services, including services that are
treated as capital costs, for Pepco. Amounts charged to Pepco by
these companies for the years ended December 31, 2008, 2007 and 2006 were
approximately $11 million, $26 million and $15 million,
respectively.
In addition to the transactions
described above, Pepco’s financial statements include the following related
party transactions in its Statements of Earnings:
Money
Pool Balance with Pepco Holdings (included in short-term debt
)
-
$(96)
(a)
Pepco
bills customers on behalf of Pepco Energy Services where customers have
selected Pepco Energy Services as their alternative supplier or where
Pepco Energy Services has performed work for certain government agencies
under a General Services Administration area-wide
agreement.
278
PEPCO
(15)
QUARTERLY FINANCIAL
INFORMATION (UNAUDITED)
The quarterly data presented below
reflect all adjustments necessary in the opinion of management for a fair
presentation of the interim results. Quarterly data normally vary
seasonally because of temperature variations and differences between summer and
winter rates. Therefore, comparisons by quarter within a year are not
meaningful.
2008
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$
525
$
539
$
728
$
530
$
2,322
Total
Operating Expenses
482
475
(a)
627
(c)
482
2,066
Operating
Income
43
64
101
48
256
Other
Expenses
(18)
(19)
(21)
(18)
(76)
Income
Before Income Tax Expense
25
45
80
30
180
Income
Tax Expense
10
14
(b)
34
6
(d)
64
Net
Income
15
31
46
24
116
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$
15
$
31
$
46
$
24
$
116
2007
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$
507
$
495
$
693
$
506
$
2,201
Total
Operating Expenses
477
450
562
(e)
464
1,953
Operating
Income
30
45
131
42
248
Other
Expenses
(15)
(14)
(17)
(15)
(61)
Income
Before Income Tax Expense
15
31
114
27
187
Income
Tax Expense
6
13
30
(f)
13
62
Net
Income
9
18
84
14
125
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$
9
$
18
$
84
$
14
$
125
(a)
Includes
a $4 million adjustment to correct an understatement of operating expenses
for prior periods dating back to February 2005 where late payment
fees were incorrectly recognized.
(b)
Includes
$3 million of after-tax interest income related to the tentative
settlement of the IRS mixed service cost issue and $2 million of after-tax
interest income received in 2008 on the Maryland state tax
refund.
(c)
Includes
a $3 million charge related to an adjustment in the accounting for certain
restricted stock awards granted under the Long-Term Incentive Plan
(LTIP).
(d)
Includes
$2 million of after-tax net interest income on uncertain and effectively
settled tax positions and a benefit of $3 million (including a $2 million
correction of prior period errors) related to additional analysis of
deferred tax balances completed in
2008.
(e)
Includes
$33 million benefit ($20 million after-tax) from settlement of Mirant
bankruptcy claims.
(f)
Includes
$20 million benefit ($18 million net of fees) related to Maryland income
tax refund and a charge of $3 million related to additional analysis of
deferred tax balances completed in
2007.
279
PEPCO
THIS
PAGE LEFT INTENTIONALLY BLANK.
280
DPL
Management’s
Report on Internal Control over Financial Reporting
The management of DPL is responsible
for establishing and maintaining adequate internal control over financial
reporting. Because of inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Management assessed its internal
control over financial reporting as of December 31, 2008 based on the
framework in Internal Control
— Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on its assessment,
the management of DPL concluded that its internal control over financial
reporting was effective as of December 31, 2008.
This Annual Report on Form 10-K does
not include an attestation report of DPL’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit DPL to provide only management’s report in this
Form 10-K.
281
DPL
Report
of Independent Registered Public Accounting Firm
To the
Shareholder and Board of Directors of
Delmarva
Power & Light Company
In our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Delmarva Power &
Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December31, 2008 and December 31, 2007, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2008 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a)(2) presents fairly, in
all material respects, the information set forth therein when read in
conjunction with the related financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company’s management. Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our
audits. We conducted our audits of these statements in accordance
with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
As
discussed in Note 12 to the financial statements, the Company changed its manner
of accounting and reporting for uncertain tax positions in 2007.
The
accompanying Notes are an integral part of these Financial
Statements.
287
DPL
NOTES TO FINANCIAL
STATEMENTS
DELMARVA
POWER & LIGHT COMPANY
(1) ORGANIZATION
Delmarva Power & Light Company
(DPL) is engaged in the transmission and distribution of electricity in Delaware
and portions of Maryland and Virginia (until the sale of its Virginia assets on
January 2, 2008), and provides gas distribution service in northern
Delaware. Additionally, DPL supplies electricity at regulated rates
to retail customers in its territories who do not elect to purchase electricity
from a competitive supplier. The regulatory term for this service
varies by jurisdiction as follows:
In this Form 10-K, DPL also refers to
these supply services generally as Default Electricity Supply. DPL is
a wholly owned subsidiary of Conectiv, which is wholly owned by Pepco Holdings,
Inc. (Pepco Holdings or PHI).
In
January 2008, DPL completed the sale of its retail electric distribution
assets and the sale of its wholesale electric transmission assets, both located
on the Eastern Shore of Virginia. For a discussion of the sales of the Virginia
assets, see Note (14), “Commitment and Contingencies — Regulatory and Other
Matters — Sale of Virginia Retail Electric Distribution and Wholesale
Transmission Assets.”
Impact of the Current
Capital and Credit Market Disruptions
The
recent disruptions in the capital and credit markets have had an impact on DPL’s
business. While these conditions have required DPL to make certain
adjustments in its financial management activities, DPL believes that it
currently has sufficient liquidity to fund its operations and meet its financial
obligations. These market conditions, should they continue, however,
could have a negative effect on DPL’s financial condition, results of operations
and cash flows.
Liquidity
Requirements
DPL depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, DPL historically has relied on the issuance of
commercial paper and short-term notes and on bank lines of credit to supplement
internally generated cash from operations. DPL’s primary credit
source is PHI’s $1.5 billion syndicated credit facility, under which DPL can
borrow funds, obtain letters of credit and support the issuance of commercial
paper in an amount up to $500 million (subject to the limitation that the total
utilization by DPL and PHI’s other utility subsidiaries cannot exceed $625
million). This facility is in effect until May 2012 and consists of
commitments from 17 lenders, no one of which is responsible for more than 8.5%
of the total commitment.
288
DPL
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, DPL has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. After giving effect to
outstanding letters of credit and commercial paper, PHI’s utility subsidiaries
have an aggregate of $843 million in combined cash and borrowing capacity under
the credit facility at December 31, 2008. During the months of
January and February 2009, the average daily amount of the combined cash and
borrowing capacity of PHI’s utility subsidiaries was $831 million and ranged
from a low of $673 million to a high of $1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, DPL has
identified a number of cash and liquidity conservation measures, including
opportunities to defer capital expenditures due to lower than anticipated
growth. Several measures to reduce expenditures have been
taken. Additional measures could be undertaken if conditions
warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, DPL issued $250 million in
long-term debt securities in November, with the proceeds used to refund
short-term debt incurred to finance utility construction and operations on a
temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
DPL participates in several of the
pension and postretirement benefit plans sponsored by PHI and its subsidiaries
for their employees. While the plans have not experienced any
significant impact in terms of liquidity or counterparty exposure due to the
disruption of the capital and credit markets, the recent stock market declines
have caused a decrease in the market value of benefit plan assets in 2008. DPL
expects to contribute approximately $10 million to the pension plan in
2009.
(2)
SIGNIFICANT ACCOUNTING
POLICIES
Use of
Estimates
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States
of America (GAAP) requires management to make certain estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses,
and related disclosures of contingent assets and liabilities in the financial
statements and accompanying notes. Although DPL believes that its
estimates and assumptions are reasonable, they are based upon information
available to management at the time the estimates are made. Actual results may
differ significantly from these estimates.
Significant matters that involve the
use of estimates include the assessment of contingencies, the calculation of
future cash flows and fair value amounts for use in asset impairment
evaluations, fair value calculations (based on estimated market pricing)
associated with derivative instruments, pension and other postretirement
benefits assumptions, unbilled revenue calculations, the assessment of the
probability of recovery of regulatory assets, and
289
DPL
income
tax provisions and reserves. Additionally, DPL is subject to legal,
regulatory, and other proceedings and claims that arise in the ordinary course
of its business. DPL records an estimated liability for these
proceedings and claims when the loss is determined to be probable and is
reasonably estimable.
Change in Accounting
Estimates
During
2007, as a result of the depreciation study presented as part of DPL’s Maryland
rate case, the Maryland Public Service Commission (MPSC) approved new lower
depreciation rates for DPL’s Maryland distribution assets.
Revenue
Recognition
DPL recognizes revenues upon delivery
of electricity and gas to its customers, including amounts for services
rendered, but not yet billed (unbilled revenue). DPL recorded amounts
for unbilled revenue of $52 million and $50 million as of December 31, 2008
and 2007, respectively. These amounts are included in “Accounts
receivable.” DPL calculates unbilled revenue using an output based
methodology. This methodology is based on the supply of electricity
or gas intended for distribution to customers. The unbilled revenue
process requires management to make assumptions and judgments about input
factors such as customer sales mix, temperature, and estimated power line losses
(estimates of electricity expected to be lost in the process of its transmission
and distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, and if the actual results differ
from the projected results, the impact could be material. Revenues
from non-regulated electricity and gas sales are included in Electric revenues
and Natural Gas revenues, respectively.
Taxes
related to the consumption of electricity and gas by its customers, such as
fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as
such, are billed to customers and recorded in Operating
Revenues. Accruals for these taxes by DPL are recorded in Other
taxes. Excise tax related generally to the consumption of gasoline by
DPL in the normal course of business is charged to operations, maintenance or
construction, and is de minimis.
Taxes Assessed by a
Governmental Authority on Revenue-Producing Transactions
Taxes included in DPL’s gross revenues
were $15 million, $13 million and $14 million for the years ended December 31,2008, 2007 and 2006, respectively.
Accounting for
Derivatives
DPL uses derivative instruments
(forward contracts, futures, swaps, and exchange-traded and over-the-counter
options) primarily to reduce gas commodity price volatility while limiting its
customers’ exposure to increases in the market price of gas. DPL also
manages commodity risk with physical natural gas and capacity contracts that are
not classified as derivatives. The primary goal of these activities
is to reduce the exposure of its regulated retail gas customers to natural gas
price fluctuations. All premiums paid and other transaction costs
incurred as part of DPL’s natural gas hedging activity, in addition to all gains
and losses related to hedging activities, are fully recoverable through the fuel
adjustment clause approved by the Delaware Public Service Commission (DPSC), and
are deferred under Statement of Financial Accounting Standards (SFAS) No. 71
until recovered. At December 31, 2008, there was a net
deferred
290
DPL
derivative
payable of $56 million, offset by a $56 million regulatory asset. At
December 31, 2007, there was a net deferred derivative payable of $13
million, offset by a $13 million regulatory asset.
Long-Lived Asset Impairment
Evaluation
DPL evaluates certain long-lived assets
to be held and used (for example, equipment and real estate) to determine if
they are impaired whenever events or changes in circumstances indicate that
their carrying amount may not be recoverable. Examples of such events
or changes include a significant decrease in the market price of a long-lived
asset or a significant adverse change in the manner an asset is being used or
its physical condition. A long-lived asset to be held and used is
written down to fair value if the sum of its expected future undiscounted cash
flows is less than its carrying amount.
For long-lived assets that can be
classified as assets to be disposed of by sale, an impairment loss is recognized
to the extent that the assets’ carrying amount exceeds their fair value
including costs to sell.
Income
Taxes
DPL, as an indirect subsidiary of Pepco
Holdings, is included in the consolidated federal income tax return of
PHI. Federal income taxes are allocated to DPL based upon the taxable
income or loss amounts, determined on a separate return basis.
In 2006, the Financial Accounting
Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for
Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the criteria
for recognition of tax benefits in accordance with Statement of SFAS No. 109,
“Accounting for Income Taxes,” and prescribes a financial statement recognition
threshold and measurement attribute for a tax position taken or expected to be
taken in a tax return. Specifically, it clarifies that an entity’s
tax benefits must be “more likely than not” of being sustained prior to
recording the related tax benefit in the financial statements. If the
position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. DPL applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,2007.
The financial statements include
current and deferred income taxes. Current income taxes represent the amounts of
tax expected to be reported on DPL’s state income tax returns and the amount of
federal income tax allocated from Pepco Holdings.
Deferred income tax assets and
liabilities represent the tax effects of temporary differences between the
financial statement and tax basis of existing assets and liabilities and are
measured using presently enacted tax rates. The portion of DPL’s deferred tax
liability applicable to its utility operations that has not been recovered from
utility customers represents income
291
DPL
taxes
recoverable in the future and is included in “regulatory assets” on the Balance
Sheets. See Note (7), “Regulatory Assets and Regulatory Liabilities,”
for additional discussion.
Deferred income tax expense generally
represents the net change during the reporting period in the net deferred tax
liability and deferred recoverable income taxes.
DPL recognizes interest on under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plant purchased in prior years are reported on the Balance Sheets as Investment
tax credits. These investment tax credits are being amortized to
income over the useful lives of the related utility plant.
Consolidation of Variable
Interest Entities
In accordance with the provisions of
FIN 46R entitled “Consolidation of Variable Interest Entities,” DPL consolidates
those variable interest entities where DPL has been determined to be primary
beneficiary. FIN 46R addresses conditions under which an entity
should be consolidated based upon variable interests rather than voting
interests.
DPL Onshore Wind
Transactions
In 2008,
DPL entered into three onshore wind power purchase arrangements (PPAs) for
energy and renewable energy credits (RECs) to help serve a portion of its
requirements under the State of Delaware’s Renewable Energy Portfolio Standards
Act, which requires that 20 percent of total load needed in Delaware be produced
from renewable sources by 2019. The DPSC has approved all three
agreements, and payments under the agreements are expected to start in 2009 at
the earliest.
DPL has
exclusive rights to the energy and RECs in amounts up to a total between 120 and
150 megawatts under the PPAs. The lengths of the contracts range
between 15 and 20 years. DPL is only obligated to purchase energy and
RECs in amounts generated and delivered by the sellers at rates that are
primarily fixed. Recent disruptions in the capital and credit markets
could result in delays in the start dates for these PPAs. If the PPAs
are not initiated by the specified dates, DPL has the right to terminate the
PPAs. DPL’s maximum exposure to loss under the PPAs is the extent to
which the market prices for energy and RECs fall below the contractual purchase
price.
DPL
concluded that two of the PPAs were leases in accordance with the guidance in
Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an
Arrangement Contains a Lease” (EITF 01-8), but that DPL did not own the assets
under the lease during construction in accordance with EITF Issue
No. 97-10, “The Effect of Lessee Involvement in Asset
Construction.” DPL concluded that it is not the primary beneficiary
under the third PPA because it will only receive 50 percent of the output from
the facility and it will not absorb a majority of the risks or rewards as
compared to the debt and equity investors in the facility. DPL
concluded that consolidation is not required for any of these PPAs under FIN
46(R).
292
DPL
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, cash invested in money market funds, and commercial paper held with
original maturities of three months or less. Additionally, deposits
in PHI’s “money pool,” which DPL and certain other PHI subsidiaries use to
manage short-term cash management requirements, are considered cash
equivalents. Deposits in the money pool are guaranteed by
PHI. PHI deposits funds in the money pool to the extent that the pool
has insufficient funds to meet the needs of its participants, which may require
PHI to borrow funds for deposit from external sources.
Restricted Cash
Equivalents
Restricted cash equivalents represents
cash either held as collateral or pledged as collateral, and is restricted from
use for general corporate purposes.
Accounts Receivable and
Allowance for Uncollectible Accounts
DPL’s accounts receivable balance
primarily consists of customer accounts receivable, other accounts receivable,
and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned
in the current period but not billed to the customer until a future date
(usually within one month after the receivable is recorded).
DPL
maintains an allowance for uncollectible accounts. DPL determines the
amount of the allowance based on specific identification of material amounts at
risk by customer and maintains a general reserve based on its’ historical
collection experience. The adequacy of this allowance is assessed on a quarterly
basis by evaluating all known factors such as the aging of the receivables,
historical collection experience, the economic and competitive environment, and
changes in the creditworthiness of its customers. Although management believes
its allowance is adequate, it cannot anticipate with any certainty the changes
in the financial condition of its customers. As a result, DPL records
adjustments to the allowance for uncollectible accounts in the period the new
information is known.
Inventories
Included
in inventories are:
- generation,
transmission, and distribution materials and supplies; and
- natural
gas.
DPL
utilizes the weighted average cost method of accounting for inventory items.
Under this method, an average price is determined for the quantity of units
acquired at each price level and is applied to the ending quantity to calculate
the total ending inventory balance. Materials and supplies inventory are
generally charged to inventory when purchased and then expensed or capitalized
to plant, as appropriate, when installed.
The cost
of natural gas, including transportation costs, is included in inventory when
purchased and charged to fuel expense when used.
293
DPL
Goodwill
Goodwill
represents the excess of the purchase price of an acquisition over the fair
value of the net assets acquired at the acquisition date. All of DPL’s goodwill
was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL tests
its goodwill for impairment annually as of July 1, and whenever an event
occurs or circumstances change in the interim that would more likely than not
reduce the fair value of DPL below its carrying amount. Factors that may result
in an interim impairment test include, but are not limited to: a change in
identified reporting units; an adverse change in business conditions; a
protracted decline in PHI’s stock price causing its market capitalization to
fall below its book value; an adverse regulatory action; or an impairment of
long-lived assets. DPL performed its annual impairment test on July1, 2008, and an interim impairment test at December 31, 2008, and no impairment
was recorded as described in Note (6), “Goodwill.”
Regulatory Assets and
Regulatory Liabilities
Certain aspects of DPL’s utility
businesses are subject to regulation by the DPSC and the MPSC, and, until the
sale of its Virginia assets on January 2, 2008, were regulated by the Virginia
State Corporation Commission (VSCC). The transmission and wholesale
sale of electricity by DPL is regulated by the Federal Energy Regulatory
Commission (FERC). DPL’s interstate transportation and wholesale sale
of natural gas are regulated by FERC.
Based on the regulatory framework in
which it has operated, DPL has historically applied, and in connection with its
transmission and distribution business continues to apply, the provisions of
SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation.” SFAS No. 71 allows regulated entities, in appropriate
circumstances, to establish regulatory assets and to defer the income statement
impact of certain costs that are expected to be recovered in future
rates. Management’s assessment of the probability of recovery of
regulatory assets requires judgment and interpretation of laws, regulatory
commission orders, and other factors. If management subsequently
determines, based on changes in facts or circumstances, that a regulatory asset
is not probable of recovery, then the regulatory asset will be eliminated
through a charge to earnings.
As part of the new electric service
distribution base rates for DPL approved by the MPSC, effective in June 2007,
the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail
customers. For customers to which the BSA applies, DPL recognizes
distribution revenue based on an approved distribution charge per
customer. From a revenue recognition standpoint, the BSA thus
decouples the distribution revenue recognized in a reporting period from the
amount of power delivered during the period. Pursuant to this
mechanism, DPL recognizes either (a) a positive adjustment equal to the amount
by which revenue from Maryland retail distribution sales falls short of the
revenue that DPL is entitled to earn based on the approved distribution charge
per customer, or (b) a negative adjustment equal to the amount by which revenue
from such distribution sales exceeds the revenue that DPL is entitled to earn
based on the approved distribution charge per customer (a Revenue Decoupling
Adjustment). A positive Revenue Decoupling Adjustment is recorded as
a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a
regulatory liability. The net Revenue Decoupling Adjustment at
December 31, 2008 is a regulatory asset and is included in the “Other” line item
on the table of regulatory asset balances in Note (7), “Regulatory Assets and
Regulatory Liabilities.”
294
DPL
Property, Plant and
Equipment
Property, plant and equipment are
recorded at original cost, including labor, materials, asset retirement costs
and other direct and indirect costs including capitalized interest. The carrying
value of property, plant and equipment is evaluated for impairment whenever
circumstances indicate the carrying value of those assets may not be recoverable
under the provisions of SFAS No. 144. Upon retirement, the cost of
regulated property, net of salvage, is charged to accumulated
depreciation. For additional information regarding the treatment of
retirement obligations, see the “Asset Retirement Obligations” section included
in this Note.
The annual provision for depreciation
on electric and gas property, plant and equipment is computed on the
straight-line basis using composite rates by classes of depreciable
property. Accumulated depreciation is charged with the cost of
depreciable property retired, less salvage and other
recoveries. Property, plant and equipment other than electric and gas
facilities is generally depreciated on a straight-line basis over the useful
lives of the assets. The system-wide composite depreciation rate for
each of 2008, 2007 and 2006 for DPL’s transmission and distribution system
property was approximately 3%.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Statements of Earnings.
DPL recorded AFUDC for borrowed funds
of $1 million for each of the years ended December 31, 2008, 2007, and
2006.
DPL recorded amounts for the equity
component of AFUDC of $1 million, zero and $1 million for the years ended
December 31, 2008, 2007 and 2006, respectively.
Leasing
Activities
DPL’s
lease transactions can include plant, office space, equipment, software and
vehicles. In accordance with SFAS No. 13, “Accounting for Leases”
(SFAS No. 13), these leases are classified as operating
leases.
Operating
Leases
An
operating lease generally results in a level income statement charge over the
term of the lease, reflecting the rental payments required by the lease
agreement. If rental payments are not made on a straight-line basis, DPL’s
policy is to recognize the increases on a straight-line basis over the lease
term unless another systematic and rational allocation basis is more
representative of the time pattern in which the leased property is physically
employed.
295
DPL
Amortization of Debt
Issuance and Reacquisition Costs
DPL defers and amortizes debt issuance
costs and long-term debt premiums and discounts over the lives of the respective
debt issues. Costs associated with the redemption of debt are also
deferred and amortized over the lives of the new issues.
Asset Removal
Costs
In accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations,” asset removal costs are
recorded as regulatory liabilities. At December 31, 2008 and
2007, $234 million is reflected as a regulatory liability in the accompanying
Balance Sheets.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory retirement plan that covers substantially all employees of DPL
(the PHI Retirement Plan) and certain employees of other Pepco Holdings
subsidiaries. Pepco Holdings also provides supplemental retirement
benefits to certain eligible executives and key employees through nonqualified
retirement plans and provides certain postretirement health care and life
insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted
for in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,”
as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106
and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance
with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than
Pensions,” as amended by SFAS No. 158. Pepco Holdings’
financial statement disclosures were prepared in accordance with SFAS No. 132,
“Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as
amended by SFAS No. 158.
DPL participates in benefit plans
sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not
have an impact on its financial condition and cash flows.
Dividend
Restrictions
In addition to its future financial
performance, the ability of DPL to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory
laws, may require the prior approval of DPL’s utility regulatory
commissions before dividends can be paid and (ii) the prior rights of holders of
existing and future preferred stock, mortgage bonds and other long-term debt
issued by DPL and any other restrictions imposed in connection with the
incurrence of liabilities. DPL has no shares of preferred stock
outstanding. DPL had approximately $95 million and $118 million of
restricted retained earnings at December 31, 2008 and 2007,
respectively.
Reclassifications and
Adjustments
Certain
prior year amounts have been reclassified in order to conform to current year
presentation.
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DPL
During
2008, DPL recorded adjustments to correct errors in Other Operation and
Maintenance expenses for prior periods dating back to May 2006 during which (i)
customer late payment fees were incorrectly recognized and (ii) stock-based
compensation expense related to certain restricted stock awards granted under
the Long-Term Incentive Plan was understated. These adjustments, which were not
considered material either individually or in the aggregate, resulted in a total
increase in Other Operation and Maintenance expenses of $5 million for the year
ended December 31, 2008, all of which related to prior periods.
(3) NEWLY ADOPTED ACCOUNTING
STANDARDS
Statement of Financial Accounting
Standards (SFAS) No. 157, “Fair Value Measurements”
(SFAS No.
157)
SFAS No. 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies to
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. Under SFAS No.
157, fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants in
the most advantageous market using the best available information. The
provisions of SFAS No. 157 were effective for financial statements beginning
January 1, 2008 for DPL.
In
February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157
to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair
Value Measurements for Purposes of Lease Classification or Measurement under
Statement 13” (FSP 157-1), that removed fair value measurement for the
recognition and measurement of lease transactions from the scope of SFAS No.
157. The effective date of FSP 157-1 was for financial statement
periods beginning January 1, 2008 for DPL.
Also in
February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement
No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all
non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually), until financial statement reporting periods
beginning January 1, 2009 for DPL.
DPL applied the guidance of FSP 157-1
and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS
No. 157 on January 1, 2008 did not result in a transition adjustment to
beginning retained earnings and did not have a material impact on DPL’s overall
financial condition, results of operations, or cash flows. SFAS No.
157 also required new disclosures regarding the level of pricing observability
associated with financial instruments carried at fair value. This
additional disclosure is provided in Note (13), “Fair Value
Disclosures.” DPL is currently evaluating the impact of FSP 157-2 and
does not anticipate that the application of FSP 157-2 to its other non-financial
assets and non-financial liabilities will materially affect its overall
financial condition, results of operations, or cash flows.
In September 2008, the Securities
and Exchange Commission and FASB issued guidance on fair value measurements,
which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining
the Fair Value of a Financial Asset When the Market for that Asset is Not
Active.”
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DPL
This
guidance clarifies the application of SFAS No. 157 to assets in an inactive
market and illustrates how to determine the fair value of a financial asset in
an inactive market. The guidance was effective beginning with the
September 30, 2008 reporting period for DPL, and has not had a material
impact on DPL’s results.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities—including an Amendment of FASB Statement No.
115” (SFAS No.
159)
SFAS No. 159 permits entities to elect
to measure eligible financial instruments at fair value. SFAS No. 159
applies to other accounting pronouncements that require or permit fair value
measurements and does not require any new fair value measurements. On
January 1, 2008, DPL elected not to apply the fair value option for its
eligible financial assets and liabilities.
FASB Staff Position (FSP) FIN 39-1,
“Amendment of FASB Interpretation No. 39” (FSP FIN 39-1)
FSP FIN 39-1 amended certain portions
of FIN 39. The FSP replaces the terms “conditional contracts” and “exchange
contracts” in FIN 39 with the term “derivative instruments” as defined in SFAS
Statement No. 133 “Accounting for Derivative Instrument and Hedging Activities”
(SFAS No. 133). The FSP also amends FIN 39 to allow for the
offsetting of fair value amounts for the right to reclaim cash collateral or
receivables, or the obligation to return cash collateral or payables, arising
from the same master netting arrangement as the derivative instruments. FSP
FIN 39-1 applied to financial statements beginning January 1, 2008 for
DPL.
DPL retrospectively adopted the
provisions of FSP FIN 39-1 and elected to offset the net fair value amounts
recognized for derivative instruments and fair value amounts recognized for
related collateral positions executed with the same counterparty under a master
netting arrangement. The effect of retrospective application of FSP
FIN 39-1 was not material at December 31, 2007 and, as such, no amounts
were reclassified.
SFAS No. 162, “The Hierarchy of
Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS
No. 162, which identifies the sources of accounting principles and the hierarchy
for selecting the principles to be used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with
GAAP. Moving the GAAP hierarchy into the accounting literature directs the
responsibility for applying the hierarchy to the reporting entity, rather than
just to the auditors.
SFAS No. 162 was effective for DPL
as of November 15, 2008 and did not result in a change in accounting for
DPL. Therefore, the provisions of SFAS No. 162 did not have a
material impact on DPL’s overall financial condition, results of operations,
cash flows and disclosure.
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DPL
FSP
FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain
Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued
FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that
provide credit protection through credit derivatives (including embedded credit
derivatives) within the scope of SFAS No. 133, and guarantees within the scope
of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others.”
For
credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature
and fair value of the credit derivative, the approximate term, the reasons for
entering the derivative, the events requiring performance, and the current
status of the payment/performance risk. It also requires disclosures
of the maximum potential amount of future payments without any reduction for
possible recoveries under collateral provisions, recourse provisions, or
liquidation proceeds. DPL has not provided credit protection to
others through the credit derivatives within the scope of SFAS No.
133.
For
guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status
of the payment/performance risk and whether the current status is based on
external credit ratings or current internal groupings used to manage
risk. If internal groupings are used, then information is required
about how the groupings are determined and used for managing risk.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2008 for DPL. Comparative disclosures are
only required for periods ending after initial adoption. The new
guarantee disclosures did not have a material impact on DPL.
FSP
FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about
Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP
FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP
FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original
pronouncements. The disclosure requirements in SFAS No. 140 for transfers
of financial assets are to include disclosure of (i) a transferor’s continuing
involvement in transferred financial assets, and (ii) how a transfer of
financial assets to a special-purpose entity affects an entity’s financial
position, financial performance, and cash flows. The principal objectives of the
disclosure requirements in Interpretation 46(R) are to outline (i) significant
judgments in determining whether an entity should consolidate a variable
interest entity (VIE), (ii) the nature of any restrictions on consolidated
assets, (iii) the risks associated with the involvement in the VIE, and (iv) how
the involvement with the VIE affects an entity’s financial position, financial
performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is
effective for DPL’s December 31, 2008 financial statements. This FSP
has no material impact to DPL’s overall financial condition, results of
operations, or cash flows as it relates to SFAS No. 140. DPL’s
FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies
- Consolidation of Variable Interest Entities.”
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DPL
(4) RECENTLY ISSUED ACCOUNTING
STANDARDS, NOT YET ADOPTED
SFAS No. 141(R) replaces FASB Statement
No. 141, “Business Combinations,” and retains the fundamental requirements that
the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business
combination. However, SFAS No. 141 (R) expands the definition of a
business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer
to recognize changes in the amount of its deferred tax benefits that are
realizable because of a business combination either in income from continuing
operations or directly in contributed capital, depending on the
circumstances.
In
January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and
Liabilities Assumed in a Business Combination that Arise from Contingencies”
(FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and
liabilities arising from contingencies in a business combination. The
FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a
business combination that arise from contingences be measured at fair value in
accordance with SFAS No. 157 if the acquisition date can be reasonably
determined. If not, then the asset or liability would be measured at
the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN
14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance
provided in FSP FAS 141(R)-a applies prospectively to business combinations for
which the acquisition date is on or after January 1, 2009 for
DPL. DPL has evaluated the impact of SFAS No. 141(R) and does
not anticipate its adoption will have a material impact on its overall financial
condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No.
160)
SFAS No. 160 establishes new accounting
and reporting standards for a non-controlling interest (also called a “minority
interest”) in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a minority interest in a subsidiary is
an ownership interest in the consolidated entity that should be separately
reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and
reporting standards that require (i) the ownership interests and the related
consolidated net income in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, and
presented separately on the face of the consolidated statement of
income, (ii) the changes in a parent’s ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for as
equity transactions, and (iii) when a subsidiary is deconsolidated, any retained
non-controlling equity investment in the former subsidiary must be initially
measured at fair value.
SFAS No. 160 is effective prospectively
for financial statement reporting periods beginning January 1, 2009 for
DPL, except for the presentation and disclosure requirements. The
presentation and disclosure requirements apply retrospectively for all periods
presented.
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DPL
DPL has
evaluated the impact of SFAS No. 160 and does not anticipate its adoption
will have a material impact on its overall financial condition, results of
operations, cash flows or disclosure.
SFAS No. 161, “Disclosures about
Derivative Instruments and Hedging Activities—an Amendment of FASB Statement No.
133” (SFAS No. 161)
In March 2008, the FASB issued
SFAS No. 161, which changes the disclosure requirements for derivative
instruments and hedging activities. Entities will be required to
provide qualitative disclosures about derivatives objectives and strategies,
fair value amounts of gains and losses on derivative instruments which before
were optional, disclosure about credit-risk-related contingent features in
derivative agreements, and information on the potential effect on an entity’s
liquidity from using derivatives.
SFAS No. 161 requires that the gross
fair value of derivative instruments and gross gains and losses be
quantitatively disclosed in a tabular format to provide a more complete picture
of the location in an entity’s financial statements of both the derivative
positions existing at period end and the effect of using derivatives during the
reporting period. The FASB provides an option for hedged items to be
presented in a tabular or non-tabular format.
SFAS No. 161 is effective for financial
statement reporting periods beginning January 1, 2009 for
DPL. SFAS No. 161 encourages but does not require disclosures for
earlier periods presented for comparative purposes at initial
adoption. DPL is currently evaluating the impact SFAS No. 161
may have on its March 31, 2009 quarterly disclosures.
EITF
Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with
a Third Party Credit Enhancement” (EITF 08-5)
In
September 2008, the FASB issued EITF 08-5 to provide guidelines for the
determination of the unit of accounting for a liability issued with an
inseparable third-party credit enhancement when it is measured or disclosed at
fair value on a recurring basis. EITF 08-5 applies to entities that incur
liabilities with inseparable third-party credit enhancements or guarantees that
are recognized or disclosed at fair value. This would include
guaranteed debt obligations, derivatives, and other instruments that are
guaranteed by third parties.
The
effect of the credit enhancement may not be included in the fair value
measurement of the liability, even if the liability is an inseparable
third-party credit enhancement. The issuer is required to disclose the existence
of the inseparable third-party credit enhancement on the issued
liability.
EITF 08-5
is effective on a prospective basis in reporting periods on and after January 1,2009 for DPL. The effect of initial application shall be included in
the change in fair value in the period of adoption. DPL is currently
evaluating the impact on its accounting and disclosures.
In November 2008, the FASB issued EITF
08-6 to address the accounting for equity method investments including: (i) how
an equity method investment should initially be measured, (ii) how it should be
tested for impairment, and (iii) how an equity method
investee’s
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DPL
issuance
of shares should be accounted for. The EITF concludes that initial
carrying value of an equity method investment can be determined using the
accumulation model in SFAS 141(R), “Business Combination (revised 2007),” and
other-than-temporary impairments should be recognized in accordance with
paragraph 19(h) of Accounting Principles Board Opinion No. 18, “The Equity
Method of Accounting for Investments in Common Stock.”
This EITF
is effective for DPL beginning January 1, 2009. DPL is currently
evaluating the impact on its accounting and disclosures.
FSP
FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP FAS 132(R)-1)
In
December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. The required disclosures under this FSP would
expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about
Pensions and Other Postretirement Benefits—an amendment of FASB Statements No.
87, 88, and 106,” to be in line with SFAS No. 157 required
disclosures.
The
disclosures are to provide users an understanding of the investment allocation
decisions made, factors used in the investment policies and strategies, plan
assets by major investment types, inputs and valuation techniques used to
measure fair value of plan assets, significant concentration of risk within the
plan, and the effects of fair value measurement using significant unobservable
inputs (Level 3 as defined in SFAS No. 157) on changes in plan assets for
the period.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2009 for DPL and earlier application is
permitted. Comparative disclosures under this provision are not
required for earlier periods presented. DPL is currently evaluating
the impact on its disclosures.
(5) SEGMENT
INFORMATION
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” DPL has
one segment, its regulated utility business.
(6) GOODWILL
DPL’s
July 1, 2008 annual impairment test indicated that its goodwill was not
impaired. DPL performed an interim impairment test at December 31,2008, as the market capitalization of PHI for a significant period in the fourth
quarter of 2008 was lower than its book value. The December 31, 2008
impairment test indicated that the goodwill balance was not impaired under
either of the discounted cash flow models.
To
estimate the fair value of DPL’s business, DPL reviewed the results from two
discounted cash flow models. The models differ in the method used to
calculate the terminal value of the reporting unit. One estimate of
terminal value is based on a constant, annual cash flow growth rate that is
consistent with DPL’s plan, and the other estimate of terminal value
is
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DPL
based on
a multiple of earnings before interest, taxes, depreciation, and amortization
that management believes is consistent with relevant market multiples for
comparable utilities. Each model uses a cost of capital appropriate
for a regulated utility as the discount rate for the estimated cash flows
associated with the reporting unit. Neither valuation model evidenced
impairment of goodwill. PHI has consistently used this valuation
model to estimate the fair value of DPL’s business since the adoption of SFAS
No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142).
The
estimation of fair value is dependent on a number of factors, including but not
limited to future growth assumptions, operating and capital expenditure
requirements, and capital costs, and changes in these factors could materially
impact the results of impairment testing. The estimated cash flows
were sourced from DPL’s forecast, and they incorporate current plans for capital
expenditures and regulatory ratemaking cases. Assumptions and
methodologies used in the models were consistent with historical experience,
including assumptions concerning the recovery of operating costs and capital
expenditures. The discount rate employed reflected DPL’s estimated
cost of capital. Sensitive, interrelated and uncertain variables that
could decrease the estimated fair value of DPL’s business include utility sector
market performance, sustained poor economic conditions, the results of
rate-making proceedings, higher operating and capital expenditure requirements,
a significant increase in the cost of capital and other factors.
With the
current volatile general market conditions and the disruptions in the credit and
capital markets, DPL will continue to closely monitor whether there is goodwill
impairment.
(7) REGULATORY ASSETS AND
REGULATORY LIABILITIES
The components of DPL’s regulatory
asset balances at December 31, 2008 and 2007 are as follows:
2008
2007
(Millions of dollars)
Deferred
energy supply costs
$ 19
$ 16
Deferred
income taxes
74
73
Deferred
debt extinguishment costs
19
18
Phase
in credits
10
38
COPCO
acquisition adjustment
38
40
Other
82
40
Total
Regulatory Assets
$242
$225
The
components of DPL’s regulatory liability balances at December 31, 2008 and
2007 are as follows:
2008
2007
(Millions
of dollars)
Deferred
energy supply costs
$ 1
$ 1
Deferred
income taxes due to customers
39
39
Asset
removal costs
234
234
Other
3
2
Total
Regulatory Liabilities
$277
$276
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DPL
A description for each category of
regulatory assets and regulatory liabilities follows:
Deferred Energy Supply
Costs: The regulatory asset primarily represents deferred
costs associated with a net under-recovery of Default Electricity Supply costs
incurred in Maryland and deferred fuel costs for DPL’s gas
business. The gas deferred fuel costs are recovered over a twelve
month period and include a return component. The regulatory
liability primarily represents deferred costs associated with a net
over-recovery of Default Electricity Supply costs incurred in Delaware. The Default Electricity
Supply deferrals do not earn a return.
Deferred Income
Taxes: Represents a receivable from our customers for tax
benefits DPL has previously flowed through before the company was ordered to
provide deferred income taxes. As the temporary differences between
the financial statement and tax basis of assets reverse, the deferred
recoverable balances are reversed. There is no return on these
deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and, if
approved, will be amortized to interest expense during the authorized rate
recovery period. A return is received on these
deferrals.
Phase In
Credits: Represents phase-in credits for participating
Maryland and Delaware residential and small commercial customers to mitigate the
immediate impact of significant rate increases due to energy costs in
2006. The deferral period for Delaware was May 1, 2006 to January 1,2008 with recovery to occur over a 17-month period beginning January
2008. The Delaware deferral will be recovered from participating
customers on a straight-line basis. The deferral period for Maryland
was June 1, 2006 to June 1, 2007, with the recovery occurring over an 18-month
period beginning June 2007 and ending in 2008. There is no return on
these deferrals.
COPCO Acquisition
Adjustment: On July 19, 2007, the Maryland PSC issued an order
which provided for the recovery of a portion of DPL’s goodwill. As a
result of this order, $41 million in DPL goodwill has been transferred to a
regulatory asset. It will earn a 12.95% return and will be amortized
from August 2007 through August 2018.
Other: Includes
losses associated with DPL’s natural gas hedging activity which earns a return
and under-recovery of administration costs associated with Maryland and Delaware
SOS that do not receive a return.
Deferred Income Taxes Due to
Customers: Represents the portion of deferred income tax
liabilities applicable to DPL’s utility operations that has not been reflected
in current customer rates, for which future payment to customers is
probable. As temporary differences between the financial statement
and tax basis of assets reverse, deferred recoverable income taxes are
amortized. There is no return on these deferrals.
Asset Removal
Costs: DPL’s depreciation rates include a component for
removal costs, as approved by its federal and state regulatory
commissions. DPL has recorded a regulatory liability for their
estimate of the difference between incurred removal costs and the level of
removal costs recovered through rates.
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DPL
Other: Includes
over-recovery of procurement and administration costs associated with Maryland
and Delaware SOS. There is no return on these deferrals.
(8) LEASING
ACTIVITIES
DPL leases an 11.9% interest in the
Merrill Creek Reservoir. The lease is an operating lease and payments
over the remaining lease term, which ends in 2032, are $107 million in the
aggregate. DPL also has long-term leases for certain other facilities
and equipment. Total future minimum operating lease payments for DPL,
including the Merrill Creek Reservoir lease, as of December 31, 2008
are $9 million in 2009, $17 million in 2010, $5 million in 2011, $5 million in
2012, $5 million in 2013, and $99 million after 2013.
Rental expense for operating leases,
including the Merrill Creek Reservoir lease, was $9 million, $10
million and $11 million for the years ended December 31, 2008, 2007 and 2006,
respectively.
(9) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
The balances of all property, plant and
equipment, which are primarily electric transmission and distribution property,
are stated at original cost. Utility plant is generally subject to a
first mortgage lien.
Asset
Sales
In
January 2008, DPL completed (i) the sale of its retail electric
distribution assets on the Eastern Shore of Virginia to A&N Electric
Cooperative for a purchase price of approximately $49 million, after closing
adjustments, and (ii) the sale of its wholesale electric transmission assets
located on the Eastern Shore of Virginia to Old Dominion Electric Cooperative
for a purchase price of approximately $5 million, after closing
adjustments.
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DPL
(10) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
DPL accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2008, 2007, and 2006, DPL was responsible for $3 million,
$4 million and $1 million, respectively, of the pension and other postretirement
net periodic benefit cost incurred by Pepco Holdings. In 2008 and
2007, DPL made no contributions to the PHI Retirement Plan, and $9 million and
$8 million, respectively to other postretirement benefit plans. At
December 31, 2008 and 2007, DPL’s prepaid pension expense of
$184 million and $178 million, and other postretirement benefit
obligation of $4 million and $5 million, included in Other Deferred Credits,
effectively represent assets and benefit obligations resulting from DPL’s
participation in the Pepco Holdings benefit plan. DPL expects to
contribute approximately $10 million to the pension plan in 2009.
The
bonds are subject to mandatory tender on July 1,2010.
(b)
The
bonds are subject to mandatory tender on May 1,2011.
(c)
The
bonds were subject to mandatory tender on August 1,2008.
(d)
The
insured auction rate tax-exempt bonds were repurchased by DPL at par due
to the disruption in the credit markets. The bonds are considered
extinguished for accounting purposes; however, DPL intends to remarket or
reissue the bonds to the public in
2009.
The outstanding First Mortgage Bonds
issued by DPL are subject to a lien on substantially all of DPL’s property,
plant and equipment.
Maturities of long-term debt and
sinking fund requirements during the next five years are as follows: zero in
2009, $31 million in 2010, $35 million in 2011, zero in 2012, $250 million in
2013, and $371 million thereafter.
DPL’s long-term debt is subject to
certain covenants. DPL is in compliance with all
requirements.
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DPL
SHORT-TERM
DEBT
DPL, a regulated utility, has
traditionally used a number of sources to fulfill short-term funding needs, such
as commercial paper, short-term notes, and bank lines of
credit. Proceeds from short-term borrowings are used primarily to
meet working capital needs, but may also be used to temporarily fund long-term
capital requirements. A detail of the components of DPL’s short-term
debt at December 31, 2008 and 2007 is as follows.
2008
2007
(Millions
of dollars)
Commercial
paper
$ -
$ 24
Intercompany
borrowings
-
157
Variable
rate demand bonds
96
105
Bank
Loan
150
-
Total
$246
$286
Commercial
Paper
DPL maintains an ongoing commercial
paper program of up to $500 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with PHI’s other utility subsidiaries, Potomac
Electric Power Company (Pepco) and Atlantic City Electric Company
(ACE).
DPL had no commercial paper outstanding
at December 31, 2008 and $24 million of commercial paper outstanding at December31, 2007. The weighted average interest rates for commercial paper
issued during 2008 and 2007 were 3.88% and 5.35%, respectively. The weighted
average maturity for commercial paper issued during 2008 and 2007 was five days
and four days, respectively.
Variable Rate Demand
Bonds
Variable Rate Demand Bonds (“VRDB”) are
subject to repayment on the demand of the holders and for this reason are
accounted for as short-term debt in accordance with GAAP. However, bonds
submitted for purchase are remarketed by a remarketing agent on a best efforts
basis. DPL expects the bonds submitted for purchase will continue to be
remarketed successfully due to the credit worthiness of the company and because
the remarketing agent resets the interest rate to the then-current market rate.
The company also may utilize one of the fixed rate/fixed term conversion options
of the bonds to establish a maturity which corresponds to the date of final
maturity of the bonds. On this basis, DPL views VRDB as a source of long-term
financing. During 2008, $9 million of VRDB’s were tendered to the
company. If market conditions are favorable, DPL intends to remarket
these bonds during 2009. The VRDB outstanding in 2008 mature as
follows: 2017 ($26 million), 2024 ($24 million), 2028 ($16 million),
and 2029 ($30 million). The weighted average interest rate for VRDB
was 3.24% during 2008 and 3.87% during 2007. Of the $96 million in
VRDB’s, $72 million of DPL’s obligations are secured by first mortgage bonds,
which provide collateral to the investors in the event of a default by
DPL.
308
DPL
Bank
Loan
In March
2008, DPL obtained a $150 million unsecured term loan that matures in July
2009. Interest on the loan is calculated at a variable
rate.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under this primary credit
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is, at the borrowing company’s election, (i) the greater of the
prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the
prevailing Eurodollar rate, plus a margin that varies according to the credit
rating of the borrower. The facility also includes a “swingline loan
sub-facility,” pursuant to which each company may make same day borrowings in an
aggregate amount not to exceed $150 million. Any swingline loan must
be repaid by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties must be true, and the borrower must be in
compliance with specified covenants, including (i) the requirement that
each borrowing company maintain a ratio of total indebtedness to total
capitalization of 65% or less, computed in accordance with the terms of the
credit agreement, which calculation excludes from the definition of total
indebtedness certain trust preferred securities and deferrable interest
subordinated debt (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than certain sales
and dispositions, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other than permitted
liens. The absence of a material adverse change in the borrower’s
business, property, and results of operations or financial condition is not a
condition to the availability of credit under the facility. The facility does
not include any rating triggers.
As a
result of severe liquidity constraints in the credit, commercial paper and
capital markets during October 2008, DPL borrowed under the $1.5 billion
credit facility. Typically, DPL issues commercial paper if required
to meet its short-term working capital requirements. Given the lack
of liquidity in the commercial paper markets, DPL borrowed under the credit
facility to maintain sufficient cash on hand to meet daily short-term operating
needs. In October 2008, DPL borrowed $150
million. At December 31, 2008, DPL did not have any borrowings under
the facility.
309
DPL
(12) INCOME
TAXES
DPL, as an indirect subsidiary of PHI,
is included in the consolidated federal income tax return of
PHI. Federal income taxes are allocated to DPL pursuant to a written
tax sharing agreement that was approved by the Securities and Exchange
Commission in connection with the establishment of PHI as a holding company as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for income taxes,
reconciliation of income tax expense, and components of deferred income tax
liabilities (assets) are shown below.
During
2008, DPL completed an analysis of its current and deferred income tax accounts
and, as a result, recorded a $2 million charge to income tax expense in 2008,
which is primarily included in “Deferred tax adjustments” in the reconciliation
provided above. In addition, during 2008 DPL recorded after-tax net
interest income of $3 million under FIN 48 primarily related to the reversal of
previously accrued interest payable resulting from a favorable tentative
settlement of the mixed service cost issue with the IRS.
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant
Accounting Policies,” DPL adopted FIN 48 effective January 1,2007. Upon adoption, DPL recorded the cumulative effect of the change
in accounting principle of $100 thousand as an increase in retained
earnings. Also upon adoption, DPL had $43 million of unrecognized tax
benefits and $10 million of related accrued interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
2008
2007
Beginning
balance as of January 1,
$
41
$
43
Tax
positions related to current year:
Additions
-
1
Tax
positions related to prior years:
Additions
35
7
Reductions
(22)
-
Settlements
-
(10)
Ending
balance as of December 31,
$
54
$
41
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits related to tax positions that have been taken or are expected
to be taken in tax returns that are not recognized in the financial statements
because, in accordance with FIN 48, management has either measured the tax
benefit at an amount less than the benefit claimed, or expected to be claimed,
or has concluded that it is not more likely than not that the tax position will
be ultimately sustained.
For the majority of these tax
positions, the ultimate deductibility is highly certain, but there is
uncertainty about the timing of such deductibility. At December 31,2008, DPL had no unrecognized tax benefits that, if recognized, would lower the
effective tax rate.
Interest and Penalties
DPL recognizes interest and penalties
relating to its uncertain tax positions as an element of income tax
expense. For the years ended December 31, 2008 and 2007, DPL
recognized $5 million of interest income before tax ($3 million after-tax) and
$2 million of interest expense before tax ($1 million after-tax), respectively,
as a component of tax expense. As of December 31, 2008 and 2007, DPL
had $3 million and $6 million, respectively, of accrued interest payable related
to effectively settled and uncertain tax positions.
311
DPL
Possible Changes to Unrecognized Tax
Benefits
It is reasonably possible that the
amount of the unrecognized tax benefit with respect to certain of DPL’s
unrecognized tax positions will significantly increase or decrease within the
next 12 months. The final settlement of the Mixed Service Cost issue or
other federal or state audits could impact the balances
significantly. At this time, other than the Mixed Service Cost issue,
an estimate of the range of reasonably possible outcomes cannot be determined.
The unrecognized benefit related to the Mixed Service Cost issue could decrease
by $22 million within the next 12 months upon final resolution of the
tentative settlement with the IRS and the obligation becomes
certain. See Note (14), “Commitments and Contingencies,” for
additional information.
Tax Years Open to
Examination
DPL, as in indirect subsidiary of PHI,
is included on PHI’s consolidated federal tax return. DPL’s federal
income tax liabilities for all years through 1999 have been determined, subject
to adjustment to the extent of any net operating loss or other loss or credit
carrybacks from subsequent years. The open tax years for the
significant states where DPL files state income tax returns (Maryland, Delaware,
and Virginia) are the same as noted above.
Components of Deferred
Income Tax Liabilities (Assets)
As of December 31,
2008
2007
(Millions
of dollars)
Deferred
Tax Liabilities (Assets)
Depreciation
and other basis differences related to plant and equipment
$339
$315
Deferred
taxes on amounts to be collected through future rates
14
13
Pension
and other postretirement benefits
72
62
Other
15
16
Total
Deferred Tax Liabilities, net
440
406
Deferred
tax assets included in Other Current Assets
8
6
Deferred
tax liabilities included in Other Current Liabilities
(2)
(2)
Total
Deferred Tax Liabilities, net - non-current
$446
$410
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement and tax basis of assets and
liabilities. The portion of the net deferred tax liability applicable
to DPL’s operations, which has not been reflected in current service rates,
represents income taxes recoverable through future rates, net and is recorded as
a regulatory asset on the balance sheet. No valuation allowance for
deferred tax assets was required or recorded at December 31, 2008 and
2007.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after
December 31, 1985, except for certain transition property. ITC
previously earned on DPL’s property continues to be normalized over the
remaining service lives of the related assets.
312
DPL
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
2008
2007
2006
(Millions
of dollars)
Gross
Receipts/Delivery
$17
$17
$19
Property
18
18
17
Environmental,
Use and Other
-
1
1
Total
$35
$36
$37
(13)
FAIR VALUE
DISCLOSURES
Effective
January 1, 2008, DPL adopted SFAS No. 157, as discussed earlier in
Note (3), which established a framework for measuring fair value and
expands disclosures about fair value measurements.
As defined in SFAS No. 157, fair value
is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date (exit price). DPL utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. Accordingly, DPL
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. DPL is able to classify fair
value balances based on the observability of those inputs. SFAS No. 157
establishes a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (level 1
measurement) and the lowest priority to unobservable inputs (level 3
measurement). The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:
Level 1 — Quoted prices are available
in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
Level 2 — Pricing inputs are other than
quoted prices in active markets included in level 1, which are either directly
or indirectly observable as of the reporting date. Level 2 includes
those financial instruments that are valued using broker quotes in liquid
markets, and other observable pricing data. Level 2 also includes
those financial instruments that are valued using internally developed
methodologies that have been corroborated by observable market data through
correlation or by other means. Significant assumptions are observable
in the marketplace throughout the full term of the instrument, can be derived
from observable data or are supported by observable levels at which transactions
are executed in the marketplace.
Level 3 — Pricing inputs include
significant inputs that are generally less observable than those from objective
sources. Level 3 includes those financial investments that are valued
using models or other valuation methodologies. DPL’s Level 3
instruments are natural gas options.
313
DPL
Some
non-standard assumptions are used in their forward valuation to adjust for
the pricing; otherwise, most of the options follow NYMEX
valuation. A few of the options have no significant NYMEX components,
and have to be priced using internal volatility assumptions. Some of
the options do not expire until December 2011. All of the
options are part of the natural gas hedging program approved by the Delaware
Public Service Commission.
Level 3
instruments classified as executive deferred compensation plan assets are life
insurance policies that are valued using the cash surrender value of the
policies. Since these values do not represent a quoted price in an active market
they are considered Level 3.
The following table sets forth by level
within the fair value hierarchy DPL’s financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31,2008. As required by SFAS No. 157, financial assets and liabilities
are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. DPL’s assessment of the
significance of a particular input to the fair value measurement requires the
exercise of judgment, and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy
levels.
Quoted
Prices in Active Markets for Identical Instruments
(Level 1)
Significant
Other Observable Inputs (Level 2)
Significant
Unobservable Inputs
(Level 3)
ASSETS
Cash
equivalents
$
129
$
129
$
-
$
-
Executive
deferred
compensation
plan assets
4
3
-
1
$
133
$
132
$
-
$
1
LIABILITIES
Derivative
instruments
$
56
$
29
$
3
$
24
Executive
deferred compensation plan liabilities
1
-
1
-
$
57
$
29
$
4
$
24
314
DPL
A
reconciliation of the beginning and ending balances of DPL’s fair value
measurements using significant unobservable inputs (level 3) is shown below (in
millions of dollars):
Gains
(realized and unrealized) included in earnings for the period above are
reported in Fuel and Purchased Energy Expense and Other Operation and
Maintenance Expense as follows:
Fuel
and Purchased Energy Expense
Other
Operation and Maintenance Expense
Total
losses included in earnings for
the
period above
$
(14)
$
-
Change
in unrealized losses relating to
assets
still held at reporting date
$
(17)
$
-
The estimated fair values of DPL’s
non-derivative financial instruments at December 31, 2008 and 2007 are
shown below.
2008
2007
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
(Millions
of dollars)
Long-term
debt
$686
$682
$552
$544
The fair values of the Long-term debt,
which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Unsecured
Tax-Exempt Bonds, Medium-Term Notes, and Unsecured Notes, including amounts due
within one year, were derived based on current market prices, or for issues with
no market price available, were based on discounted cash flows using current
rates for similar issues with similar terms and remaining
maturities.
(14) COMMITMENTS AND
CONTINGENCIES
Rate
Proceedings
In the most recent electric service
distribution base rate cases filed by DPL in Maryland, and in a natural gas
distribution case filed by DPL in Delaware, DPL proposed the adoption of a BSA
for retail customers. As more fully discussed below, the
implementation of a BSA has been approved for electric service in
Maryland. A method of revenue decoupling similar to a
BSA,
315
DPL
referred
to as a modified fixed variable rate design (MFVRD), has been adopted in
Delaware, which will be implemented in the context of DPL’s next Delaware base
rate case. Under the BSA, customer delivery rates are subject to
adjustment (through a surcharge or credit mechanism), depending on whether
actual distribution revenue per customer exceeds or falls short of the approved
revenue-per-customer amount. The BSA increases rates if actual
distribution revenues fall below the level approved by the applicable commission
and decreases rates if actual distribution revenues are above the approved
level. The result is that, over time, DPL collects its authorized
revenues for distribution deliveries. As a consequence, a BSA
“decouples” revenue from unit sales consumption and ties the growth in revenues
to the growth in the number of customers. Some advantages of the BSA
are that it (i) eliminates revenue fluctuations due to weather and changes
in customer usage patterns and, therefore, provides for more predictable utility
distribution revenues that are better aligned with costs, (ii) provides for
more reliable fixed-cost recovery, (iii) tends to stabilize customers’
delivery bills, and (iv) removes any disincentives for DPL to promote
energy efficiency programs for its customers, because it breaks the link between
overall sales volumes and delivery revenues. The MVFRD adopted in
Delaware relies primarily upon a fixed customer charge (i.e., not tied to the
customer’s volumetric consumption) to recover the utility’s fixed costs, plus a
reasonable rate of return. Although different from the BSA, DPL
believes that the MFRVD can serve as an appropriate revenue decoupling
mechanism.
Delaware
On August 29, 2008, DPL submitted
its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting a 14.8% increase in
the level of GCR. On September 16, 2008, the DPSC issued an
initial order approving the requested increase, which became effective on
November 1, 2008, subject to refund pending final DPSC approval after
evidentiary hearings.
On January 26, 2009, DPL submitted
to the DPSC an interim GCR filing, requesting a 6.6% decrease in the level of
GCR. On February 5, 2009, the DPSC issued an initial order
approving the requested decrease, to become effective on March 1, 2009,
subject to refund pending final DPSC approval after evidentiary
hearings.
Maryland
In July 2007, the MPSC issued an
order in DPL’s electric service distribution rate case, which included approval
of a BSA. The order approved an annual increase in distribution rates
of approximately $15 million (including a decrease in annual depreciation
expense of approximately $1 million). The approved distribution
rate reflects a return on equity (ROE) of 10%. The rate increases
were effective as of June 16, 2007, and remained in effect for an initial
period until July 19, 2008, pending a Phase II proceeding in which the MPSC
considered the results of an audit of DPL’s cost allocation manual, as filed
with the MPSC, to determine whether a further adjustment to the rates was
required. On July 18, 2008, the MPSC issued an order covering
the Phase II proceedings, denying any further adjustment to DPL’s rates, thus
making permanent the rate increases approved in the July 2007
order. The MPSC also issued an order on August 4, 2008, further
explaining its July 18 order.
DPL has filed a general notice of
appeal of the MPSC July 2007 and the July 18 and August 4, 2008
orders. The appeal challenges the MPSC’s failure to implement
permanent rates in accordance with Maryland law, and seek judicial review of the
MPSC’s denial of DPL’s rights
316
DPL
to
recover an increased share of the PHI Service Company costs and the costs of
performing a MPSC-mandated management audit. The case currently is
pending before the Circuit Court for Baltimore City. Under the
procedural schedule set by the court, DPL will file a consolidated brief on or
before March 9, 2009, specifying the basis for its requested
relief.
Federal Energy Regulatory
Commission
On August 18, 2008, DPL submitted an
application with FERC for incentive rate treatments in connection with PHI’s
230-mile, 500-kilovolt Mid-Atlantic Power Pathway transmission
project. The application requested that FERC include DPL’s
Construction Work in Progress in its transmission rate base, an ROE adder of 150
basis points (for a total ROE of 12.8%) and the recovery of prudently incurred
costs in the event the project is abandoned or terminated for reasons beyond
DPL’s control. On October 31, 2008, FERC issued an order
approving the application.
Sale
of Virginia Retail Electric Distribution and Wholesale Transmission
Assets
In January 2008, DPL completed
(i) the sale of its retail electric distribution assets on the Eastern
Shore of Virginia to A&N Electric Cooperative (A&N) for a purchase price
of approximately $49 million, after closing adjustments, and (ii) the
sale of its wholesale electric transmission assets located on the Eastern Shore
of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of
approximately $5 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 purchased
(including, in the A&N transaction, most environmental
liabilities). A&N delayed final payment of approximately
$3 million, which was due on June 2, 2008, due to a dispute in the
final true-up amounts. On October 21, 2008, DPL and A&N
entered into a Settlement Agreement pursuant to which A&N paid
$3 million to DPL, and an additional $1 million was distributed to DPL
pursuant to an escrow agreement.
Environmental
Litigation
DPL is subject to regulation by various
federal, regional, state, and local authorities with respect to the
environmental effects of its operations, including air and water quality
control, solid and hazardous waste disposal, and limitations on land
use. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. DPL may incur costs to clean up
currently or formerly owned facilities or sites found to be contaminated, as
well as other facilities or sites that may have been contaminated due to past
disposal practices. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from DPL’s customers,
environmental clean-up costs incurred by DPL would be included in its cost of
service for ratemaking purposes.
Metal Bank/Cottman Avenue
Site. In the early 1970s, DPL sold scrap transformers, some of
which may have contained some level of PCBs, to a metal reclaimer operating at
the Metal Bank/Cottman Avenue site in Philadelphia, Pennsylvania, owned by a
nonaffiliated company. In 1987, DPL was notified by the United States
Environmental Protection Agency (EPA) that it, along with a number of other
utilities and non-utilities, was a potentially responsible party in connection
with the PCB contamination at the site. In 1999, DPL entered into a
de minimis settlement with EPA and paid less than a million dollars to resolve
its liability
317
DPL
for
cleanup costs at the Metal Bank/Cottman Avenue site. The de minimis
settlement did not resolve DPL’s responsibility for natural resource damages, if
any, at the site. DPL believes that any liability for natural
resource damages at this site will not have a material adverse effect on its
financial position, results of operations or cash flows.
IRS
Mixed Service Cost Issue
During
2001, DPL changed its method of accounting with respect to capitalizable
construction costs for income tax purposes. The change allowed DPL to
accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $62
million for DPL, primarily attributable to DPL’s 2001 tax returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require DPL
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on those proposed regulations, PHI in its 2005 federal
tax return adopted an alternative method of accounting for capitalizable
construction costs that management believed would be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which was
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that DPL had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
U.S. Office of Appeals of the Internal Revenue Service (IRS).
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. In June 2008, PHI
received from the IRS an offer of settlement pertaining to DPL for the tax years
2001 through 2004. DPL is substantially in agreement with this
proposed settlement. Based on the terms of the proposal, DPL expects
the final settlement amount to be less than the $121 million previously
deposited.
On the
basis of the tentative settlement, DPL updated its estimated liability related
to mixed service costs and, as a result, recorded in the quarter ended June 30,2008, a net reduction in its liability for unrecognized tax benefits of $1
million and recognized after-tax interest income of $2 million.
Contractual
Obligations
As of December 31, 2008, DPL’s
contractual obligations under non-derivative fuel and power purchase contracts
were $482 million in 2009, $412 million in 2010 to 2011, $47 million in 2012 to
2013, and $136 million in 2014 and thereafter.
318
DPL
(15) RELATED PARTY
TRANSACTIONS
PHI Service Company provides various
administrative and professional services to PHI and its regulated and
unregulated subsidiaries including DPL. The cost of these services is
allocated in accordance with cost allocation methodologies set forth in the
service agreement using a variety of factors, including the subsidiaries’ share
of employees, operating expenses, assets, and other cost causal
methods. These intercompany transactions are eliminated by PHI in
consolidation and no profit results from these transactions at
PHI. PHI Service Company costs directly charged or allocated to DPL
for the years ended December 31, 2008, 2007 and 2006 were $111 million, $108
million, and $101 million, respectively.
In addition to the PHI Service Company
charges described above, DPL’s financial statements include the following
related party transactions in its Statements of Earnings:
Money
Pool Interest Accrued (included in interest accrued)
-
$ (1)
319
DPL
(16) QUARTERLY FINANCIAL
INFORMATION (UNAUDITED)
The quarterly data presented below
reflect all adjustments necessary in the opinion of management for a fair
presentation of the interim results. Quarterly data normally vary
seasonally because of temperature variations and differences between summer and
winter rates. Therefore, comparisons by quarter within a year are not
meaningful.
2008
First
Quarter
Second
Quarter
Third
Quarter
Fourth Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$
411
$
372
$
401
$355
$1,539
Total
Operating Expenses
364
341
376
(c)
310
1,391
Operating
Income
47
31
25
45
148
Other
Expenses
(8)
(7)
(8)
(12)
(35)
Income
Before Income Tax Expense
39
24
17
33
113
Income
Tax Expense
13
(a)
8
(b)
6
18
(d)
45
Net
Income
26
16
11
15
68
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$
26
$
16
$
11
$
15
$ 68
2007
First
Quarter
Second
Quarter
Third
Quarter
Fourth Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$
422
$
330
$
399
$345
$1,496
Total
Operating Expenses
385
310
367
312
1,374
Operating
Income
37
20
32
33
122
Other
Expenses
(10)
(9)
(10)
(11)
(40)
Income
Before Income Tax Expense
27
11
22
22
82
Income
Tax Expense
11
2
11
(e)
13
(e)
37
Net
Income
16
9
11
9
45
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$
16
$
9
$
11
$ 9
$ 45
(a)
Includes
$3 million of after-tax net interest income on uncertain tax positions
primarily related to casualty
losses.
(b)
Includes
$2 million of after-tax interest income related to the tentative
settlement of the IRS mixed service cost
issue.
(c)
Includes
a $2 million charge related to an adjustment in the accounting for certain
restricted stock awards granted under the Long-Term Incentive Plan (LTIP)
and a $4 million adjustment to correct an understatement of operating
expenses for prior periods dating back to May 2006 where late payment fees
were incorrectly recognized.
(d)
Includes
$3 million of after-tax net interest expense on uncertain and effectively
settled tax positions (primarily associated with the reversal of the
majority of the interest income recognized on uncertain tax positions
related to casualty losses in the first quarter) and a charge of $2
million to correct prior period errors related to additional analysis of
deferred tax balances completed in
2008.
(e)
Includes
a charge of $1 million in the third quarter and $2 million in the fourth
quarter related to additional analysis of deferred tax balances completed
in 2007.
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321
ACE
Management’s
Report on Internal Control over Financial Reporting
The management of ACE is responsible
for establishing and maintaining adequate internal control over financial
reporting. Because of inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Management assessed its internal
control over financial reporting as of December 31, 2008 based on the framework
in Internal Control —
Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on its assessment, the management
of ACE concluded that its internal control over financial reporting was
effective as of December 31, 2008.
This Annual Report on Form 10-K does
not include an attestation report of ACE’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit ACE to provide only management’s report in this
Form 10-K.
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Report
of Independent Registered Public Accounting Firm
To the
Shareholder and Board of Directors of
Atlantic
City Electric Company
In our
opinion, the consolidated financial statements listed in the accompanying index
present fairly, in all material respects, the financial position of Atlantic
City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and
its subsidiaries at December 31, 2008 and December 31, 2007, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2008 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our
opinion, the financial statement schedule listed in the index appearing under
Item 15(a)(2) presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement
schedule are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our
audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
As
discussed in Note 11 to the consolidated financial statements, the Company
changed its manner of accounting and reporting for uncertain tax positions in
2007.
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
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NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
ATLANTIC
CITY ELECTRIC COMPANY
(1) ORGANIZATION
Atlantic City Electric Company (ACE) is
engaged in the transmission and distribution of electricity in southern New
Jersey. In addition, ACE provides Default Electricity Supply, which
is the supply of electricity at regulated rates to retail customers in its
service territory who do not elect to purchase electricity from a competitive
supplier. Default Electricity Supply is also known as Basic
Generation Service (BGS). ACE is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or
PHI).
In addition to its electricity
transmission and distribution operations, during 2006 ACE owned a 2.47%
undivided interest in the Keystone electric generating facility, a 3.83%
undivided interest in the Conemaugh electric generating facility (with a
combined generating capacity of 108 megawatts), and also owned the B.L. England
electric generating facility (with a generating capacity of 447
megawatts). On September 1, 2006, ACE sold its interests in the
Keystone and Conemaugh generating facilities and on February 8, 2007, ACE
completed the sale of the B.L. England generating facility.
Impact of the Current
Capital and Credit Market Disruptions
The
recent disruptions in the capital and credit markets have had an impact on ACE’s
business. While these conditions have required ACE to make certain
adjustments in its financial management activities, ACE believes that it
currently has sufficient liquidity to fund its operations and meet its financial
obligations. These market conditions, should they continue, however,
could have a negative effect on ACE’s financial condition, results of operations
and cash flows.
Liquidity
Requirements
ACE depends on access to the capital
and credit markets to meet its liquidity and capital requirements. To
meet its liquidity requirements, ACE historically has relied on the issuance of
commercial paper and short-term notes and on bank lines of credit to supplement
internally generated cash from operations. ACE’s primary credit
source is PHI’s $1.5 billion syndicated credit facility, under which ACE can
borrow funds, obtain letters of credit and support the issuance of commercial
paper in an amount up to $500 million (subject to the limitation that the total
utilization by ACE and PHI’s other utility subsidiaries cannot exceed $625
million). This facility is in effect until May 2012 and consists of
commitments from 17 lenders, no one of which is responsible for more than 8.5%
of the total commitment.
Due to the recent capital and credit
market disruptions, the market for commercial paper was severely restricted for
most companies. As a result, ACE has not been able to issue
commercial paper on a day-to-day basis either in amounts or with maturities that
it typically has required for cash management purposes. After giving effect to
outstanding letters of credit and commercial paper, PHI’s utility subsidiaries
have an aggregate of $843 million in combined cash and borrowing capacity under
the credit facility at December 31, 2008. During the months of
January and February 2009, the average daily amount of the combined cash and
borrowing
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capacity
of PHI’s utility subsidiaries was $831 million and ranged from a low of $673
million to a high of $1 billion.
To address the challenges posed by the
current capital and credit market environment and to ensure that it will
continue to have sufficient access to cash to meet its liquidity needs, ACE has
identified a number of cash and liquidity conservation measures, including
opportunities to defer capital expenditures due to lower than anticipated
growth. Several measures to reduce expenditures have been
taken. Additional measures could be undertaken if conditions
warrant.
Due to the financial market conditions,
which have caused uncertainty of short-term funding, ACE issued $250 million in
long-term debt securities in November. The proceeds were used to
refund short-term debt incurred to finance utility construction and operations
on a temporary basis and incurred to fund the temporary repurchase of tax-exempt
auction rate securities.
Pension
and Postretirement Benefit Plans
ACE participates in pension and
postretirement benefit plans sponsored by PHI for employees. While
the plans have not experienced any significant impact in terms of liquidity or
counterparty exposure due to the disruption of the capital and credit markets,
the recent stock market declines have caused a decrease in the market value of
benefit plan assets in 2008. ACE expects to contribute approximately $60 million
to the pension plan in 2009.
(2) SIGNIFICANT ACCOUNTING
POLICIES
Consolidation
Policy
The accompanying consolidated financial
statements include the accounts of ACE and its wholly owned subsidiaries. All
intercompany balances and transactions between subsidiaries have been
eliminated. ACE uses the equity method to report investments,
corporate joint ventures, partnerships, and affiliated companies where it holds
a 20% to 50% voting interest and cannot exercise control over the operations and
policies of the investee. Individual interests in several jointly
owned electric plants previously held by ACE, and certain transmission and other
facilities currently held are consolidated in proportion to ACE’s percentage
interest in the facility.
In accordance with the provisions of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R,
entitled “Consolidation of Variable Interest Entities” (FIN 46R), ACE
consolidates those variable interest entities where ACE has been determined to
be primary beneficiary. FIN 46R addresses conditions when an entity
should be consolidated based upon variable interests rather than voting
interests. For additional information, see the FIN 46R discussion
later in this Note.
Use of
Estimates
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States
of America (GAAP) requires management to make certain estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses,
and related disclosures of contingent assets and liabilities in the
consolidated
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ACE
financial
statements and accompanying notes. Although ACE believes that its
estimates and assumptions are reasonable, they are based upon information
available to management at the time the estimates are made. Actual results may
differ significantly from these estimates.
Significant matters that involve the
use of estimates include the assessment of contingencies, the calculation of
future cash flows and fair value amounts for use in asset impairment
evaluations, pension and other postretirement benefits assumptions, unbilled
revenue calculations, the assessment of the probability of recovery of
regulatory assets, and income tax provisions and
reserves. Additionally, ACE is subject to legal, regulatory, and
other proceedings and claims that arise in the ordinary course of its
business. ACE records an estimated liability for these proceedings
and claims when the loss is determined to be probable and is reasonably
estimable.
Revenue
Recognition
ACE recognizes revenue upon delivery of
electricity to its customers, including amounts for electricity delivered but
not yet billed (unbilled revenue). ACE recorded amounts for unbilled
revenue of $45 million and $38 million as of December 31, 2008 and
December 31, 2007, respectively. These amounts are included in
“Accounts receivable.” ACE calculates unbilled revenue using an
output based methodology. This methodology is based on the supply of
electricity intended for distribution to customers. The unbilled
revenue process requires management to make assumptions and judgments about
input factors such as customer sales mix, temperature, and estimated power line
losses (estimates of electricity expected to be lost in the process of its
transmission and distribution to customers), all of which are inherently
uncertain and susceptible to change from period to period, and if the actual
results differ from the projected results, the impact could be
material.
Taxes related to the delivery of
electricity to its customers are a component of ACE’s tariffs and, as such, are
billed to customers and recorded in “Operating Revenues.” Accruals
for these taxes by ACE are recorded in “Other taxes.” Excise tax
related generally to the consumption of gasoline by ACE in the normal course of
business is charged to operations, maintenance or construction, and is de
minimis.
Taxes Assessed by a
Governmental Authority on Revenue-Producing Transactions
Taxes included in ACE’s gross revenues
were $22 million, $23 million and $22 million for the years ended December 31,2008, 2007 and 2006, respectively.
Long-Lived Asset Impairment
Evaluation
ACE evaluates certain long-lived assets
to be held and used (for example, generating property and equipment and real
estate) to determine if they are impaired whenever events or changes in
circumstances indicate that their carrying amount may not be
recoverable. Examples of such events or changes include a significant
decrease in the market price of a long-lived asset or a significant adverse
change in the manner an asset is being used or its physical
condition. A long-lived asset to be held and used is written down to
fair value if the sum of its expected future undiscounted cash flows is less
than its carrying amount.
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ACE
For long-lived assets that can be
classified as assets to be disposed of by sale, an impairment loss is recognized
to the extent that the assets’ carrying amount exceeds their fair value
including costs to sell.
Income
Taxes
ACE, as an indirect subsidiary of PHI,
is included in the consolidated federal income tax return of Pepco
Holdings. Federal income taxes are allocated to ACE based upon the
taxable income or loss amounts, determined on a separate return
basis.
In 2006, the FASB issued FIN 48,
“Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48
clarifies the criteria for recognition of tax benefits in accordance with
Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for
Income Taxes,” and prescribes a financial statement recognition threshold and
measurement attribute for a tax position taken or expected to be taken in a tax
return. Specifically, it clarifies that an entity’s tax benefits must
be “more likely than not” of being sustained prior to recording the related tax
benefit in the financial statements. If the position drops below the
“more likely than not” standard, the benefit can no longer be
recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. ACE applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,2007.
The consolidated financial statements
include current and deferred income taxes. Current income taxes represent the
amounts of tax expected to be reported on ACE’s state income tax returns and the
amount of federal income tax allocated from PHI.
Deferred income tax assets and
liabilities represent the tax effects of temporary differences between the
financial statement and tax basis of existing assets and liabilities, and are
measured using presently enacted tax rates. The portion of ACE’s
deferred tax liability applicable to its utility operations that has not been
recovered from utility customers represents income taxes recoverable in the
future and is included in “regulatory assets” on the Consolidated Balance
Sheets. See Note (6), “Regulatory Assets and Regulatory Liabilities,”
for additional discussion.
Deferred income tax expense generally
represents the net change during the reporting period in the net deferred tax
liability and deferred recoverable income taxes.
ACE recognizes interest on under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plant purchased in prior years are reported on the Consolidated Balance Sheets
as Investment tax credits. These investment tax credits are being
amortized to income over the useful lives of the related utility
plant.
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ACE
Discontinued
Operations
Discontinued operations are identified
and accounted for in accordance with the provisions of SFAS No. 144, “Accounting
for the Impairment or Disposal of Long-Lived Assets.” For information
regarding ACE’s discontinued operations refer to Note (16), “Discontinued
Operations” herein.
FIN 46R, “Consolidation of
Variable Interest Entities”
ACE has
power purchase agreements (PPAs) with a number of entities, including three
contracts between unaffiliated non-utility generators (NUGs) and
ACE. Due to a variable element in the pricing structure of the NUGs,
ACE potentially assumes the variability in the operations of the plants related
to these PPAs and, therefore, has a variable interest in the
entities. In accordance with the provisions of FIN 46R (revised
December 2003), entitled “Consolidation of Variable Interest Entities,” and
FSP FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB
Interpretation No. 46(R),” ACE continued, during the fourth quarter of 2008, to
conduct exhaustive efforts to obtain information from these entities, but was
unable to obtain sufficient information to conduct the analysis required under
FIN 46R to determine whether these three entities were variable interest
entities or if ACE was the primary beneficiary. As a result, ACE has
applied the scope exemption from the application of FIN 46R for enterprises that
have conducted exhaustive efforts to obtain the necessary information, but have
not been able to obtain such information.
Net purchase activities with the NUGs
for the years ended December 31, 2008, 2007 and 2006, were approximately $349
million, $327 million and $324 million, respectively, of which approximately
$305 million, $292 million and $288 million, respectively, related to power
purchases under the NUGs. ACE does not have exposure to loss under the NUGs
because cost recovery will be achieved from its customers through regulated
rates.
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, cash invested in money market funds, and commercial paper held with
original maturities of three months or less. Additionally, deposits
in PHI’s “money pool,” which ACE and certain other PHI subsidiaries use to
manage short-term cash management requirements, are considered cash
equivalents. Deposits in the money pool are guaranteed by
PHI. PHI deposits funds in the money pool to the extent that the pool
has insufficient funds to meet the needs of its participants, which may require
PHI to borrow funds for deposit from external sources.
Restricted Cash
Equivalents
Restricted cash equivalents represents
cash either held as collateral or pledged as collateral, and is restricted from
use for general corporate purposes.
Accounts Receivable and
Allowance for Uncollectible Accounts
ACE’s accounts receivable balance
primarily consists of customer accounts receivable, other accounts receivable,
and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned
in the current period but not billed to the customer until a future date
(usually within one month after the receivable is recorded).
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ACE
ACE
maintains an allowance for uncollectible accounts and changes in the allowance
are recorded as an adjustment to Other Operation and Maintenance expense in the
Consolidated Statements of Earnings. ACE determines the amount of
allowance based on specific identification of material amounts at risk by
customer and maintains a general reserve based on its historical collection
experience. The adequacy of this allowance is assessed on a quarterly basis by
evaluating all known factors such as the aging of the receivables, historical
collection experience, the economic and competitive environment, and changes in
the creditworthiness of its customers. Although management believes its
allowances is adequate, it cannot anticipate with any certainty the changes in
the financial condition of its customers. As a result, ACE records adjustments
to the allowance for uncollectible accounts in the period the new information is
known.
Inventories
Included
in inventories are generation, transmission, and distribution materials and
supplies. ACE utilizes the weighted average cost method of accounting
for inventory items. Under this method, an average price is determined for the
quantity of units acquired at each price level and is applied to the ending
quantity to calculate the total ending inventory balance. Materials and supplies
inventory are generally charged to inventory when purchased and then expensed or
capitalized to plant, as appropriate, when installed.
Regulatory Assets and
Regulatory Liabilities
Certain aspects of ACE’s utility
businesses are subject to regulation by the New Jersey Board of Public Utilities
(NJBPU). The transmission and wholesale sale of electricity by ACE is
regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in
which it has operated, ACE has historically applied, and in connection with its
transmission and distribution business continues to apply, the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the
Effects of Certain Types of Regulation.” SFAS No. 71 allows regulated entities,
in appropriate circumstances, to establish regulatory assets and to defer the
income statement impact of certain costs that are expected to be recovered in
future rates. Management’s assessment of the probability of recovery
of regulatory assets requires judgment and interpretation of laws, regulatory
commission orders, and other factors. If management subsequently
determines, based on changes in facts or circumstances, that a regulatory asset
is not probable of recovery, then the regulatory asset will be eliminated
through a charge to earnings.
Property, Plant and
Equipment
Property, plant and equipment are
recorded at original cost, including labor, materials, asset retirement costs
and other direct and indirect costs, including capitalized interest. The
carrying value of property, plant and equipment is evaluated for impairment
whenever circumstances indicate the carrying value of those assets may not be
recoverable under the provisions of SFAS No. 144. Upon retirement,
the cost of regulated property, net of salvage, is charged to accumulated
depreciation.
The annual provision for depreciation
on electric property, plant and equipment is computed on the straight-line basis
using composite rates by classes of depreciable property. Accumulated
depreciation is charged with the cost of depreciable property retired, less
salvage
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ACE
and other
recoveries. Property, plant and equipment other than electric
facilities is generally depreciated on a straight-line basis over the useful
lives of the assets. The system-wide composite depreciation rate for
each of 2008, 2007 and 2006 for ACE’s transmission and distribution system
property was 3%.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Consolidated Statements of Earnings.
ACE recorded AFUDC for borrowed funds
of $2 million, $2 million and $1 million for the years ended December 31,2008, 2007 and 2006, respectively.
ACE recorded amounts for the equity
component of AFUDC of $1 million for each of the years ended December 31, 2008,
2007 and 2006.
Leasing
Activities
ACE’s
lease transactions can include plant, office space, equipment, software and
vehicles. In accordance with SFAS No. 13, “Accounting for Leases”
(SFAS No. 13), these leases are classified as operating leases.
Operating
Leases
An
operating lease generally results in a level income statement charge over the
term of the lease, reflecting the rental payments required by the lease
agreement. If rental payments are not made on a straight-line basis,
ACE’s policy is to recognize the increases on a straight-line basis over the
lease term unless another systematic and rational allocation basis is more
representative of the time pattern in which the leased property is physically
employed.
Amortization of Debt
Issuance and Reacquisition Costs
ACE defers and amortizes debt issuance
costs and long-term debt premiums and discounts over the lives of the respective
debt issues. Costs associated with the redemption of debt are also
deferred and amortized over the lives of the new issues.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory retirement plan that covers substantially all employees of ACE
(the PHI Retirement Plan) and certain employees of other Pepco Holdings
subsidiaries. Pepco Holdings also provides supplemental retirement
benefits to certain eligible executives and key employees through nonqualified
retirement plans and provides certain postretirement health care and life
insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted
for in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,”
as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106
and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance
with SFAS
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ACE
No. 106,
“Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as
amended by SFAS No. 158. Pepco Holdings’ financial statement
disclosures were prepared in accordance with SFAS No. 132, “Employers’
Disclosures about Pensions and Other Postretirement Benefits,” as amended by
SFAS No. 158.
ACE participates in benefit plans
sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not
have an impact on its financial condition and cash flows.
Dividend
Restrictions
In addition to its future financial
performance, the ability of ACE to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory laws, may
require the prior approval of ACE’s utility regulatory commission before
dividends can be paid; (ii) the prior rights of holders of existing and future
preferred stock, mortgage bonds and other long-term debt issued by ACE and any
other restrictions imposed in connection with the incurrence of liabilities; and
(iii) certain provisions of the charter of ACE, which impose restrictions on
payment of common stock dividends for the benefit of preferred
stockholders. Currently, the restriction in the ACE charter does not
limit its ability to pay dividends. ACE had approximately $89 million
and $88 million of restricted retained earnings at December 31, 2008 and
2007, respectively.
Reclassifications and
Adjustments
Certain
prior year amounts have been reclassified in order to conform to current year
presentation.
During
2008, ACE recorded an adjustment to correct errors in Other Operation and
Maintenance expenses for certain restricted stock awards granted under the
Long-Term Incentive Plan. This adjustment, which was not considered material,
resulted in an increase in Other Operation and Maintenance expenses of $1
million for the year ended December 31, 2008, all of which related to prior
periods.
(3) NEWLY ADOPTED ACCOUNTING
STANDARDS
Statement of Financial Accounting
Standards (SFAS) No. 157, “Fair Value Measurements”
(SFAS No.
157)
SFAS No. 157 defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies to
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. Under SFAS No.
157, fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants in
the most advantageous market using the best available information. The
provisions of SFAS No. 157 were effective for financial statements beginning
January 1, 2008 for ACE.
In
February 2008, the FASB issued FSP 157-1, “Application of FASB Statement No. 157
to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair
Value Measurements for Purposes of Lease Classification or Measurement under
Statement 13” (FSP
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ACE
157-1),
that removed fair value measurement for the recognition and measurement of lease
transactions from the scope of SFAS No. 157. The effective date of
FSP 157-1 was for financial statement periods beginning January 1, 2008 for
ACE.
Also in
February 2008, the FASB issued FSP 157-2, “Effective Date of FASB Statement
No. 157” (FSP 157-2), which deferred the effective date of SFAS No. 157 for all
non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually), until financial statement reporting periods
beginning January 1, 2009 for ACE.
ACE applied the guidance of FSP 157-1
and FSP 157-2 with its adoption of SFAS No. 157. The adoption of SFAS
No. 157 on January 1, 2008 did not result in a transition adjustment to
beginning retained earnings and did not have a material impact on ACE’s overall
financial condition, results of operations, or cash flows. SFAS No.
157 also required new disclosures regarding the level of pricing observability
associated with financial instruments carried at fair value. This
additional disclosure is provided in Note (13), “Fair Value
Disclosures.” ACE is currently evaluating the impact of FSP 157-2 and
does not anticipate that the application of FSP 157-2 to its other non-financial
assets and non-financial liabilities will materially affect its overall
financial condition, results of operations, or cash flows.
In September 2008, the Securities
and Exchange Commission and FASB issued guidance on fair value measurements,
which was clarifies in October 2008 by the FASB in FSP 157-3, “Determining
the Fair Value of a Financial Asset When the Market for that Asset is Not
Active.” This guidance clarifies the application of SFAS No. 157 to
assets in an inactive market and illustrates how to determine the fair value of
a financial asset in an inactive market. The guidance was effective beginning
with the September 30, 2008 reporting period for ACE, and has not had a
material impact on ACE’s results.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities—including an Amendment of FASB Statement No.
115” (SFAS No.
159)
SFAS No. 159 permits entities to elect
to measure eligible financial instruments at fair value. SFAS No. 159
applies to other accounting pronouncements that require or permit fair value
measurements and does not require any new fair value measurements. On
January 1, 2008, ACE elected not to apply the fair value option for its
eligible financial assets and liabilities.
SFAS No. 162, “The Hierarchy of
Generally Accepted Accounting Principles” (SFAS No. 162)
In May 2008, the FASB issued SFAS
No. 162, which identifies the sources of accounting principles and the hierarchy
for selecting the principles to be used in the preparation of financial
statements of nongovernmental entities that are presented in conformity with
GAAP. Moving the GAAP hierarchy into the accounting literature directs the
responsibility for applying the hierarchy to the reporting entity, rather than
just to the auditors.
SFAS No. 162 was effective for ACE
as of November 15, 2008 and did not result in a change in accounting for
ACE. Therefore, the provisions of SFAS No. 162 did not have a
material impact on ACE’s overall financial condition, results of operations,
cash flows and disclosure.
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ACE
FSP
FAS 133-1 and FIN 45-4, “Disclosure About Credit Derivatives and Certain
Guarantees” (FSP FAS 133-1 and FIN 45-4)
In September 2008, the FASB issued
FSP FAS 133-1 and FIN 45-4, which requires enhanced disclosures by entities that
provide credit protection through credit derivatives (including embedded credit
derivatives) within the scope of SFAS No. 133, and guarantees within the scope
of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others.”
For
credit derivatives, FSP FAS 133-1 and FIN 45-4 requires disclosure of the nature
and fair value of the credit derivative, the approximate term, the reasons for
entering the derivative, the events requiring performance, and the current
status of the payment/performance risk. It also requires disclosures
of the maximum potential amount of future payments without any reduction for
possible recoveries under collateral provisions, recourse provisions, or
liquidation proceeds. ACE has not provided credit protection to
others through the credit derivatives within the scope of SFAS No.
133.
For
guarantees, FSP FAS 133-1 and FIN 45-4 requires disclosure on the current status
of the payment/performance risk and whether the current status is based on
external credit ratings or current internal groupings used to manage
risk. If internal groupings are used, then information is required
about how the groupings are determined and used for managing risk.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2008 for ACE. Comparative disclosures are
only required for periods ending after initial adoption. The new
guarantee disclosures did not have a material impact on ACE.
FSP
FAS 140-4 and FIN 46(R)-8, “Disclosures by Public Entities (Enterprises) about
Transfers of Financial Assets and Interests in Variable Interest Entities” (FSP
FAS 140-4 and FIN 46(R)-8)
In December 2008, the FASB issued FSP
FAS 140-4 and FIN 46(R)-8 to expand the disclosures under the original
pronouncements. The disclosure requirements in SFAS No. 140 for
transfers of financial assets are to include disclosure of (i) a transferor’s
continuing involvement in transferred financial assets, and (ii) how a transfer
of financial assets to a special-purpose entity affects an entity’s financial
position, financial performance, and cash flows. The principal
objectives of the disclosure requirements in Interpretation 46(R) are to outline
(i) significant judgments in determining whether an entity should consolidate a
variable interest entity (VIE), (ii) the nature of any restrictions on
consolidated assets, (iii) the risks associated with the involvement in the VIE,
and (iv) how the involvement with the VIE affects an entity’s financial
position, financial performance, and cash flows.
FSP FAS 140-4 and FIN 46(R)-8 is
effective for ACE’s December 31, 2008 financial statements. This FSP
has no material impact to ACE’s overall financial condition, results of
operations, or cash flows as it relates to SFAS No. 140. ACE’s
FIN 46(R) disclosures are provided in Note (2), “Significant Accounting Policies
- FIN 46R, Consolidation of Variable Interest Entities.”
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(4) RECENTLY ISSUED ACCOUNTING
STANDARDS, NOT YET ADOPTED
SFAS No. 141(R) replaces FASB Statement
No. 141, “Business Combinations,” and retains the fundamental requirements that
the acquisition method of accounting be used for all business combinations and
for an acquirer to be identified for each business
combination. However, SFAS No. 141 (R) expands the definition of a
business and amends FASB Statement No. 109, “Accounting for Income Taxes,” to require the acquirer
to recognize changes in the amount of its deferred tax benefits that are
realizable because of a business combination either in income from continuing
operations or directly in contributed capital, depending on the
circumstances.
In
January 2009, the FASB proposed FSP FAS 141(R)-a “Accounting for Assets and
Liabilities Assumed in a Business Combination that Arise from Contingencies”
(FSP FAS 141(R)-a), to clarify the accounting on the initial recognition and
measurement, subsequent measurement and accounting, and disclosure of assets and
liabilities arising from contingencies in a business combination. The
FSP FAS 141(R)-a requires that assets acquired and liabilities assumed in a
business combination that arise from contingences be measured at fair value in
accordance with SFAS No. 157 if the acquisition date can be reasonably
determined. If not, then the asset or liability would be measured at
the amount in accordance with SFAS 5, “Accounting for Contingencies,” and FIN
14, “Reasonable Estimate of the Amount of Loss.”
SFAS No. 141(R) and the guidance
provided in FSP FAS 141(R)-a applies prospectively to business combinations for
which the acquisition date is on or after January 1, 2009 for
ACE. ACE has evaluated the impact of SFAS No. 141(R) and does
not anticipate its adoption will have a material impact on its overall financial
condition, results of operations, or cash flows.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements—an Amendment of ARB No. 51” (SFAS No.
160)
SFAS No. 160 establishes new accounting
and reporting standards for a non-controlling interest (also called a “minority
interest”) in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a minority interest in a subsidiary is
an ownership interest in the consolidated entity that should be separately
reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and
reporting standards that require (i) the ownership interests and the related
consolidated net income in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, and
presented separately on the face of the consolidated statement of
income, (ii) the changes in a parent’s ownership interest while the parent
retains its controlling financial interest in its subsidiary be accounted for as
equity transactions, and (iii) when a subsidiary is deconsolidated, any retained
non-controlling equity investment in the former subsidiary must be initially
measured at fair value.
SFAS No. 160 is effective prospectively
for financial statement reporting periods beginning January 1, 2009 for
ACE, except for the presentation and disclosure requirements. The
presentation and disclosure requirements apply retrospectively for all periods
presented.
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ACE has
evaluated the impact of SFAS No. 160 and does not anticipate its adoption
will have a material impact on its overall financial condition, results of
operations, cash flows or disclosure.
In November 2008, the FASB issued EITF
08-6 to address the accounting for equity method investments including: (i) how
an equity method investment should initially be measured, (ii) how it should be
tested for impairment, and (iii) how an equity method investee’s issuance of
shares should be accounted for. The EITF concludes that initial carrying value
of an equity method investment can be determined using the accumulation model in
SFAS 141(R), “Business Combination (revised 2007),” and other-than-temporary
impairments should be recognized in accordance with paragraph 19(h) of
Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for
Investments in Common Stock.”
This EITF
is effective for ACE beginning January 1, 2009. ACE is currently
evaluating the impact on its accounting and disclosures.
FSP
FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”
(FSP FAS 132(R)-1)
In
December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an
employer’s disclosures about plan assets of a defined benefit pension or other
postretirement plan. The required disclosures under this FSP would
expand current disclosures under SFAS No. 132(R), “Employers’ Disclosures about
Pensions and Other Postretirement Benefits—an amendment of FASB Statements No.
87, 88, and 106,” to be in line with SFAS No. 157 required
disclosures.
The
disclosures are to provide users an understanding of the investment allocation
decisions made, factors used in the investment policies and strategies, plan
assets by major investment types, inputs and valuation techniques used to
measure fair value of plan assets, significant concentration of risk within the
plan, and the effects of fair value measurement using significant unobservable
inputs (Level 3 as defined by SFAS No. 157) on changes in plan assets for
the period.
The new
disclosures are required starting with financial statement reporting periods
ending December 31, 2009 for ACE and earlier application is
permitted. Comparative disclosures under this provision are not
required for earlier periods presented. ACE is currently evaluating
the impact on its disclosures.
(5) SEGMENT
INFORMATION
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” ACE has
one segment, its regulated utility business.
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(6) REGULATORY ASSETS AND
REGULATORY LIABILITIES
The components of ACE’s regulatory
asset balances at December 31, 2008 and 2007 are as follows:
2008
2007
(Millions
of dollars)
Securitized
stranded costs
$674
$735
Deferred
income taxes
26
22
Deferred
debt extinguishment costs
14
14
Deferred
other postretirement benefit costs
10
13
Unrecovered
purchased power contract costs
9
10
Other
33
24
Total
Regulatory Assets per Balance Sheet
$766
$818
The components of ACE’s regulatory
liability balances at December 31, 2008 and 2007 are as
follows:
2008
2007
(Millions
of dollars)
Excess
depreciation reserve
$ 74
$ 90
Deferred
energy supply costs
247
241
Federal
and New Jersey tax benefits,
related
to securitized stranded costs
28
31
Gain
from sale of divested assets
26
67
Other
2
2
Total
Regulatory Liabilities per Balance Sheet
$377
$431
A description for each category of
regulatory assets and regulatory liabilities follows:
Securitized Stranded
Costs: Represents stranded costs associated with a non-utility
generator contract termination payment and the discontinuance of the application
of SFAS No. 71 for ACE’s electricity generation business. The
recovery of these stranded costs has been securitized through the issuance by
Atlantic City Electric Transition Funding LLC (ACE Funding) of transition bonds
(Transition Bonds). A customer surcharge is collected by ACE to fund
principal and interest payments on the Transition Bonds. The stranded
costs are amortized over the life of the Transition Bonds, which mature between
2010 and 2023. A return is received on these deferrals with the
exception of taxes.
Deferred Income Taxes:
Represents a receivable from our customers for tax benefits ACE has
previously flowed through before the company was ordered to provide deferred
income taxes. As the temporary differences between the financial
statement and tax basis of assets reverse, the deferred recoverable balances are
reversed. There is no return on these deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and, if
approved, will be amortized to interest expense during the authorized rate
recovery period. A return is received on these
deferrals.
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ACE
Deferred Other Postretirement
Benefit Costs: Represents the non-cash portion of other
postretirement benefit costs deferred by ACE during 1993 through
1997. This cost is being recovered over a 15-year period that began
on January 1, 1998. There is no return on this deferral.
Unrecovered Purchased Power Contract
Costs: Represents deferred costs related to purchase power
contracts at ACE, which are being recovered from July 1994 through May 2014 and
which earn a return.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
Excess Depreciation
Reserve: The excess depreciation reserve was recorded as part
of an ACE New Jersey rate case settlement. This excess reserve is the
result of a change in estimated depreciable lives and a change in depreciation
technique from remaining life to whole life. The excess is being
amortized over an 8.25 year period, which began in June 2005. There is no return
on these deferrals.
Deferred Energy Supply Costs:
The regulatory liability primarily represents deferred costs associated
with a net over-recovery by ACE connected with the provision of Default
Electricity Supply costs and other restructuring related costs incurred by
ACE. A return is generally received on these deferrals.
Federal and New Jersey Tax Benefits,
Related to Securitized Stranded Costs: Securitized stranded
costs include a portion of stranded costs attributable to the future tax benefit
expected to be realized when the higher tax basis of the generating plants is
deducted for New Jersey state income tax purposes as well as the future benefit
to be realized through the reversal of federal excess deferred
taxes. To account for the possibility that these tax benefits may be
given to ACE’s regulated electricity delivery customers through lower rates in
the future, ACE established a regulatory liability. The regulatory
liability related to federal excess deferred taxes will remain on ACE’s
Consolidated Balance Sheets until such time as the Internal Revenue Service
issues its final regulations with respect to normalization of these federal
excess deferred taxes. There is no return on these
deferrals.
Gain from Sale of Divested
Assets: Represents (i) the balance of the net gain realized by ACE from
the sale in 2006 of its interests in the Keystone and Conemaugh generating
facilities and (ii) the balance of the net proceeds realized by ACE from the
sale in 2007 of the B.L. England generating facility and the monetization of
associated emission allowance credits. Both gains are being returned
to ACE’s ratepayers as a credit on their bills — the Keystone and Conemaugh gain
over a 33-month period that began during the October 2006 billing period and the
B.L. England and emission allowances proceeds over a 12-month period that began
during the June 2008 billing period. There is no return on these
deferrals.
(7) LEASING
ACTIVITIES
ACE leases certain types of property
and equipment for use in its operations. Rental expense for operating
leases was $9 million, $10 million and $12 million for the years ended December31, 2008, 2007 and 2006, respectively.
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ACE
Total future minimum operating lease
payments for ACE as of December 31, 2008 are $4 million in 2009, $9 million
in 2010, $1 million in 2011, $1 million in 2012, $1 million in 2013, and $21
million after 2013.
(8) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
The balances of all property, plant and
equipment, which are primarily electric transmission and distribution property,
are stated at original cost. Utility plant is generally subject to a
first mortgage lien.
Jointly Owned
Plant
ACE’s Consolidated Balance Sheet
includes its proportionate share of assets and liabilities related to jointly
owned plant. ACE has ownership interests in transmission facilities, and other
facilities in which various parties have ownership interests. ACE’s
proportionate share of operating and maintenance expenses of the jointly owned
plant is included in the corresponding expenses in ACE’s Consolidated Statements
of Earnings. ACE is responsible for providing its share of financing for the
jointly owned facilities. Information with respect to ACE’s share of
jointly owned plant as of December 31, 2008 is shown below.
Jointly Owned Plant
Ownership
Share
Plant
in
Service
Accumulated
Depreciation
(Millions
of dollars)
Transmission
Facilities
Various
$25
$17
Other
Facilities
Various
1
-
Total
$26
$17
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ACE
Asset
Sales
As discussed in Note (16),
“Discontinued Operations,” in the third quarter of 2006, ACE completed the sale
of its interests in the Keystone and Conemaugh generating facilities for
approximately $175 million (after giving effect to post-closing
adjustments). In the first quarter of 2007, ACE completed the sale of
the B.L. England generating facility for a price of $9 million. In
February 2008, ACE received an additional $4 million in settlement of an
arbitration proceeding concerning the terms of the purchase
agreement. See Note (6), “Regulatory Assets and Regulatory
Liabilities,” for treatment of gains from these sales.
(9) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
ACE accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2008, 2007, and 2006, ACE was responsible for $12 million,
$11 million and $14 million, respectively, of the pension and other
postretirement net periodic benefit cost incurred by Pepco Holdings. In 2008 and
2007, ACE made no contributions to the PHI Retirement Plan, and $7 million and
$7 million, respectively to other postretirement benefit plans. At
December 31, 2008 and 2007, ACE’s prepaid pension expense of $6 million and
$8 million, and other postretirement benefit obligation of $41 million and
$38 million, effectively represent assets and benefit obligations resulting
from ACE’s participation in the Pepco Holdings benefit plan. ACE
expects to contribute approximately $60 million to the pension plan in
2009.
Represents
a series of First Mortgage Bonds issued by ACE as collateral for an
outstanding series of senior notes issued by the company or tax-exempt
bonds issued by or for the benefit of ACE. The maturity date,
optional and mandatory prepayment provisions, if any, interest rate, and
interest payment dates on each series of senior notes or the obligations
in respect of the tax-exempt bonds are identical to the terms of the
corresponding series of collateral First Mortgage
Bonds. Payments of principal and interest on a series of senior
notes or the company’s obligation in respect of the tax-exempt bonds
satisfy the corresponding payment obligations on the related series of
collateral First Mortgage Bonds. Because each series of senior
notes and tax-exempt bonds and the corresponding series of collateral
First Mortgage Bonds securing that series of senior notes or tax-exempt
bonds effectively represents a single financial obligation, the senior
notes and the tax-exempt bonds are not separately shown on the
table.
(b)
Represents
a series of First Mortgage Bonds issued by ACE as collateral for an
outstanding series of senior notes as described in footnote (a) above that
will, at such time as there are no First Mortgage Bonds of ACE outstanding
(other than collateral First Mortgage Bonds securing payment of senior
notes), cease to secure the corresponding series of senior notes and will
be cancelled.
(c)
The
insured auction rate tax-exempt bonds were repurchased by ACE at par due
to the disruption in the credit markets. The bonds are considered
extinguished for accounting purposes; however, ACE intends to remarket or
reissue the bonds to the public in
2009.
The outstanding First Mortgage Bonds
issued by ACE are subject to a lien on substantially all of ACE’s property,
plant and equipment.
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ACE
ACE Funding was established in 2001
solely for the purpose of securitizing authorized portions of ACE’s recoverable
stranded costs through the issuance and sale of Transition Bonds. The
proceeds of the sale of each series of Transition Bonds have been transferred to
ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a
non-bypassable transition bond charge from ACE customers pursuant to bondable
stranded costs rate orders issued by the NJBPU in an amount sufficient to fund
the principal and interest payments on the Transition Bonds and related taxes,
expenses and fees (Bondable Transition Property). The assets of ACE
Funding, including the Bondable Transition Property, and the Transition Bond
charges collected from ACE’s customers are not available to creditors of ACE.
The Transition Bonds are obligations of ACE Funding and are non-recourse to
ACE.
The aggregate principal amount of
long-term debt including Transition Bonds outstanding at December 31, 2008,
that will mature in each of 2009 through 2013 and thereafter is as follows: $32
million in 2009, $35 million in 2010, $35 million in 2011, $37 million in 2012,
$108 million in 2013, and $798 million thereafter.
ACE’s long-term debt is subject to
certain covenants. ACE is in compliance with all
requirements.
SHORT-TERM
DEBT
ACE has traditionally used a number of
sources to fulfill short-term funding needs, such as commercial paper,
short-term notes, and bank lines of credit. Proceeds from short-term
borrowings are used primarily to meet working capital needs, but may also be
used to temporarily fund long-term capital requirements. A detail of
the components of ACE’s short-term debt at December 31, 2008 and 2007 is as
follows.
2008
2007
(Millions
of dollars)
Commercial
paper
$ -
$
29
Variable
rate demand bonds
1
23
Bonds
held under Standby Bond Purchase Agreement
22
-
Total
$ 23
$
52
Commercial
Paper
ACE maintains an ongoing commercial
paper program of up to $250 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with PHI’s other utility subsidiaries, Potomac
Electric Power Company (Pepco) and Delmarva Power & Light Company
(DPL).
ACE had no commercial paper outstanding
at December 31, 2008 and $29 million of commercial paper outstanding at December31, 2007. The weighted average interest rates for commercial paper
issued during 2008 and 2007 were 3.12 % and 5.45%, respectively. The
weighted average maturity for commercial paper issued during 2008 and 2007 was
four days and three days, respectively.
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ACE
Variable Rate Demand
Bonds
Variable Rate Demand Bonds (VRDB) are
subject to repayment on the demand of the holders and for this reason are
accounted for as short-term debt in accordance with GAAP. However, bonds
submitted for purchase are remarketed by a remarketing agent on a best efforts
basis. ACE expects the bonds submitted for purchase will continue to be
remarketed successfully due to the credit worthiness of the company and because
the remarketing resets the interest rate to the then-current market
rate. The company also may utilize one of the fixed rate/fixed term
conversion options of the bonds to establish a maturity which corresponds to the
date of final maturity of the bonds. On this basis, ACE views VRDB as a source
of long-term financing. During 2008, in accordance with their terms,
$22 million of VRDB were tendered to the bond trustee under a Standby Bond
Purchase Agreement (SBPA) that was created at the time of issuance to provide
liquidity for the bondholders. If market conditions are favorable,
ACE intends to remarket these bonds during 2009. The VRDB outstanding
in 2008 mature as follows: 2014 ($18 million) and 2017 ($5 million).
The weighted average interest rate for VRDB was 3.29 % and 3.59% during 2008 and
2007, respectively.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs. The aggregate borrowing limit under this primary credit
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is, at the borrowing company’s election, (i) the greater of the
prevailing prime rate and the federal funds effective rate plus 0.5% or (ii) the
prevailing Eurodollar rate, plus a margin that varies according to the credit
rating of the borrower. The facility also includes a “swingline loan
sub-facility,” pursuant to which each company may make same day borrowings in an
aggregate amount not to exceed $150 million. Any swingline loan must
be repaid by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties must be true, and the borrower must be in
compliance with specified covenants, including (i) the requirement that
each borrowing company maintain a ratio of total indebtedness to total
capitalization of 65% or less, computed in accordance with the terms of the
credit agreement, which calculation excludes from the definition of total
indebtedness certain trust preferred securities and deferrable interest
subordinated debt (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than certain sales
and dispositions, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other
than
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ACE
permitted
liens. The absence of a material adverse change in the borrower’s
business, property, and results of operations or financial condition is not a
condition to the availability of credit under the facility. The facility does
not include any rating triggers.
As a
result of severe liquidity constraints in the credit, commercial paper and
capital markets during September 2008, ACE borrowed $135 million under the $1.5
billion credit facility. Typically, ACE issues commercial paper if
required to meet its short-term working capital requirements. Given
the lack of liquidity in the commercial paper markets, ACE borrowed under the
credit facility to maintain sufficient cash on hand to meet daily short-term
operating needs. At December 31, 2008, ACE had no borrowings
under the facility.
(11) INCOME
TAXES
ACE, as an indirect subsidiary of PHI,
is included in the consolidated federal income tax return of
PHI. Federal income taxes are allocated to ACE pursuant to a written
tax sharing agreement that was approved by the Securities and Exchange
Commission in connection with the establishment of PHI as a holding company as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for consolidated income
taxes, reconciliation of consolidated income tax expense, and components of
consolidated deferred income tax liabilities (assets) are shown
below.
During
2008, ACE completed an analysis of its current and deferred income tax accounts
and, as a result, recorded a $7 million charge to income tax expense in 2008,
which is included in “Deferred tax adjustments” in the reconciliation provided
above. Also identified as part of the analysis were new uncertain tax
positions for ACE under FIN 48 (primarily representing overpayments of income
taxes in previously filed tax returns) that resulted in the recording of
after-tax net interest income of $4 million, which is included as a reduction of
income tax expense.
In
addition, during 2008 ACE recorded additional after-tax net interest income of
$10 million under FIN 48 primarily related to the reversal of previously accrued
interest payable resulting from a favorable tentative settlement of the Mixed
Service Cost issue with the IRS and a claim made with the IRS related to the tax
reporting of fuel over- and under-recoveries.
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note (2), “Significant
Accounting Policies,” ACE adopted FIN 48 effective January 1,2007. Upon adoption, ACE recorded an immaterial adjustment to
retained earnings representing the cumulative effect of the change in
accounting principle. Also upon adoption, ACE had $28 million of
unrecognized tax benefits and $3 million of related accrued
interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
2008
2007
Beginning
balance as of January 1,
$
152
$
28
Tax
positions related to current year:
Additions
1
34
Tax
positions related to prior years:
Additions
40
94
Reductions
(144)
(4)
Settlements
-
-
Ending
balance as of December 31,
$
49
$
152
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Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits related to tax positions that have been taken or are expected
to be taken in tax returns that are not recognized in the financial statements
because, in accordance with FIN 48, management has either measured the tax
benefit at an amount less than the benefit claimed, or expected to be claimed,
or has concluded that it is not more likely than not that the tax position will
be ultimately sustained.
For the majority of these tax
positions, the ultimate deductibility is highly certain, but there is
uncertainty about the timing of such deductibility. Unrecognized tax
benefits at December 31, 2008, included $2 million that, if recognized, would
lower the effective tax rate.
Interest and Penalties
ACE recognizes interest and penalties
relating to its uncertain tax positions as an element of income tax
expense. For the years ended December 31, 2008 and 2007, ACE
recognized $24 million of interest income before tax ($14 million after-tax) and
$2 million of interest income before tax ($1 million after-tax), respectively,
as a component of income tax expense. As of December 31, 2008 and
2007, ACE had $13 million of accrued interest receivable and $1 million of
accrued interest payable, respectively, related to effectively settled and
uncertain tax positions.
Possible Changes to Unrecognized Tax
Benefits
It is
reasonably possible that the amount of the unrecognized tax benefit with respect
to certain of ACE’s unrecognized tax positions will significantly increase or
decrease within the next 12 months. The final settlement of the Mixed
Service Cost issue or other federal or state audits could impact the balances
significantly. At this time, other than the Mixed Service Cost issue, an
estimate of the range of reasonably possible outcomes cannot be determined. The
unrecognized benefit related to the Mixed Service Cost issue could decrease by
$13 million within the next 12 months upon final resolution of the
tentative settlement with the IRS and the obligation becomes
certain. See Note (14), “Commitments and Contingencies,” herein for
additional information.
Tax Years Open to
Examination
ACE, as an indirect subsidiary of PHI,
is included on PHI’s consolidated federal tax return. ACE’s federal
income tax liabilities for all years through 1999 have been determined, subject
to adjustment to the extent of any net operating loss or other loss or credit
carrybacks from subsequent years. The open tax years for the
significant states where PHI files state income tax returns (New Jersey and
Pennsylvania) are the same as noted above.
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ACE
Components of Consolidated
Deferred Income Tax Liabilities (Assets)
As of December 31,
2008
2007
(Millions
of dollars)
Deferred
Tax Liabilities (Assets)
Depreciation
and other basis differences related to plant and equipment
$255
$212
Deferred
taxes on amounts to be collected through future rates
10
8
Payment
for termination of purchased power contracts with NUGs
68
73
Electric
restructuring liabilities
198
195
Fuel
and purchased energy
4
(96)
Other
(1)
(18)
Total
Deferred Tax Liabilities, net
534
374
Deferred
tax asset included in Other Current Assets
15
12
Total
Consolidated Deferred Tax Liabilities, net - non-current
$549
$386
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement and tax basis of assets and
liabilities. The portion of the net deferred tax liability applicable
to ACE’s operations, which has not been reflected
in current service rates, represents income taxes recoverable through future
rates, net and is recorded as a regulatory asset on the balance
sheet. No valuation allowance for deferred tax assets was required or
recorded at December 31, 2008 and 2007.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after
December 31, 1985, except for certain transition property. ITC
previously earned on ACE’s property continues to be normalized over the
remaining service lives of the related assets.
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
2008
2007
2006
(Millions
of dollars)
Gross
Receipts/Delivery
$21
$20
$21
Property
2
3
2
Environmental,
Use and Other
1
(1)
-
Total
$24
$22
$23
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ACE
(12) PREFERRED
STOCK
The preferred stock amounts outstanding
as of December 31, 2008 and 2007 are as follows:
Under the terms of the Company’s
Articles of Incorporation, ACE has authority to issue up to 799,979 shares of
its $100 par value Cumulative Preferred Stock. In addition, ACE has
authority to issue up to 2 million shares of No Par Preferred Stock and 3
million shares of Preference Stock without par value.
(13) FAIR VALUE
DISCLOSURES
Effective
January 1, 2008, ACE adopted SFAS No. 157, as discussed earlier in
Note (3), which established a framework for measuring fair value and
expands disclosures about fair value measurements.
As defined in SFAS No. 157, fair value
is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date (exit price). ACE utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated, or generally unobservable. Accordingly, ACE
utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. ACE is able to classify fair
value balances based on the observability of those inputs. SFAS No. 157
establishes a fair value hierarchy that prioritizes the inputs used to measure
fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (level 1
measurement) and the lowest priority to unobservable inputs (level 3
measurement). The three levels of the fair value hierarchy defined by
SFAS No. 157 are as follows:
Level 1 — Quoted prices are available
in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
Level 2 — Pricing inputs are other than
quoted prices in active markets included in level 1, which are either
directly or indirectly observable as of the reporting date. Level 2
includes those financial instruments that are valued using broker quotes in
liquid markets, and other observable pricing data. Level 2 also
includes those financial instruments that are valued using internally developed
methodologies that have been corroborated by observable market data through
correlation or by other means. Significant assumptions are observable
in the
352
ACE
marketplace
throughout the full term of the instrument, can be derived from observable data
or are supported by observable levels at which transactions are executed in the
marketplace.
Level 3 — Pricing inputs include
significant inputs that are generally less observable than those from objective
sources. Level 3 includes those financial investments that are valued
using models or other valuation methodologies.
The following table sets forth by level
within the fair value hierarchy ACE’s financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31,2008. As required by SFAS No. 157, financial assets and liabilities
are classified in their entirety based on the lowest level of input that is
significant to the fair value measurement. ACE’s assessment of the
significance of a particular input to the fair value measurement requires the
exercise of judgment, and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy
levels.
Quoted
Prices in Active Markets for Identical Instruments (Level
1)
Significant
Other Observable Inputs (Level 2)
Significant
Unobservable Inputs
(Level
3)
ASSETS
Cash
equivalents
$
76
$
76
$
-
$
-
Executive
deferred
compensation
plan assets
1
1
-
-
$
77
$
77
$
-
$
-
LIABILITIES
Executive
deferred compensation plan liabilities
$
1
$
-
$
1
$
-
$
1
$
-
$
1
$
-
The estimated fair values of ACE’s
financial instruments at December 31, 2008 and 2007 are shown
below.
2008
2007
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
(Millions
of dollars)
Long-term
debt
$610
$638
$466
$464
Redeemable
Serial Preferred Stock
$ 6
$4
$ 6
$ 4
Transition
Bonds issued by ACE Funding
$433
$431
$465
$462
The
methods and assumptions below were used to estimate, at December 31, 2008 and
2007, the fair value of each class of financial instruments shown above for
which it is practicable to estimate a value.
353
ACE
The fair values of the Long-term Debt,
which includes First Mortgage Bonds, Medium-Term Notes, and Transition Bonds
issued by ACE Funding, including amounts due within one year, were derived based
on current market prices, or for issues with no market price available, were
based on discounted cash flows using current rates for similar issues with
similar terms and remaining maturities.
The fair value of the Redeemable Serial
Preferred Stock, excluding amounts due within one year, were derived based on
quoted market prices or discounted cash flows using current rates of preferred
stock with similar terms.
(14) COMMITMENTS AND
CONTINGENCIES
Rate
Proceedings
On August 18, 2008, ACE submitted an
application with FERC for incentive rate treatments in connection with PHI’s
230-mile, 500-kilovolt Mid-Atlantic Power Pathway transmission
project. The application requested that FERC include ACE’s
Construction Work in Progress in its transmission rate base, an ROE adder of 150
basis points (for a total ROE of 12.8%) and the recovery of prudently incurred
costs in the event the project is abandoned or terminated for reasons beyond
ACE’s control. On October 31, 2008, FERC issued an order
approving the application.
Sale
of B.L. England Generating Facility
In February 2007, ACE completed
the sale of the B.L. England generating facility to RC Cape May Holdings, LLC
(RC Cape May), an affiliate of Rockland Capital Energy Investments,
LLC. In July 2007, ACE received a claim for indemnification from
RC Cape May under the purchase agreement in the amount of
$25 million. RC Cape May contends that one of the assets it
purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt
Refining Co. (Citgo), has been declared by Citgo to have been terminated due to
a failure by ACE to renew the contract in a timely manner. RC Cape
May has commenced an arbitration proceeding against Citgo seeking a
determination that the TSA remains in effect and has notified ACE of the
proceeding. The claim for indemnification seeks payment from ACE in
the event the TSA is held not to be enforceable against Citgo. While
ACE believes that it has defenses to the indemnification claim, should the
arbitrator rule that the TSA has terminated, the outcome of this matter is
uncertain. ACE notified RC Cape May of its intent to participate in
the pending arbitration. The arbitration hearings were conducted in
November 2008. A decision is expected late in the second quarter of
2009, after the filing of post-hearing memoranda in the first quarter of
2009.
Environmental
Litigation
ACE is subject to regulation by various
federal, regional, state, and local authorities with respect to the
environmental effects of its operations, including air and water quality
control, solid and hazardous waste disposal, and limitations on land
use. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. ACE may incur costs to clean up
currently or formerly owned facilities or sites found to be contaminated, as
well as other facilities or sites that may have been contaminated due to past
disposal practices. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from ACE’s
customers,
354
ACE
environmental
clean-up costs incurred by ACE would be included in its cost of service for
ratemaking purposes.
Delilah Road Landfill
Site. In 1991, the New Jersey Department of Environmental
Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at
the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In
1993, ACE, along with two other PRPs, signed an administrative consent order
with NJDEP to remediate the site. The soil cap remedy for the site
has been implemented and in August 2006, NJDEP issued a No Further Action
Letter (NFA) and Covenant Not to Sue for the site. Among other
things, the NFA requires the PRPs to monitor the effectiveness of institutional
(deed restriction) and engineering (cap) controls at the site every two
years. In September 2007, NJDEP approved the PRP group’s
petition to conduct semi-annual, rather than quarterly, ground water monitoring
for two years and deferred until the end of the two-year period a decision on
the PRP group’s request for annual groundwater monitoring
thereafter. In August 2007, the PRP group agreed to reimburse
the costs of the United States Environmental Protection Agency (EPA) in the
amount of $81,400 in full satisfaction of EPA’s claims for all past and future
response costs relating to the site (of which ACE’s share is
one-third). Effective April 2008, EPA and the PRP group entered into
a settlement agreement which will allow EPA to reopen the settlement in the
event of new information or unknown conditions at the site. Based on
information currently available, ACE anticipates that its share of additional
cost associated with this site for post-remedy operation and maintenance will be
approximately $555,000 to $600,000. On November 23, 2008, Lenox,
Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of
the U.S. Bankruptcy Code. ACE filed a proof of claim in the Lenox
bankruptcy case in February 2009. ACE believes that its liability for
post-remedy operation and maintenance costs will not have a material adverse
effect on its financial position, results of operations or cash flows regardless
of the impact of the Lenox bankruptcy.
Frontier Chemical
Site. In June 2007, ACE received a letter from the New
York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP
at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y.
based on hazardous waste manifests indicating that ACE sent in excess of 7,500
gallons of manifested hazardous waste to the site. ACE has entered
into an agreement with the other parties identified as PRPs to form a PRP group
and has informed NYDEC that it has entered into good faith negotiations with the
PRP group to address ACE’s responsibility at the site. ACE believes
that its responsibility at the site will not have a material adverse effect on
its financial position, results of operations or cash flows.
Franklin Slag Pile Superfund
Site. On November 26, 2008, ACE received a general notice
letter from EPA concerning the Franklin Slag Pile Superfund Site in
Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability
with respect to the site. If liable, ACE would be responsible for
reimbursing EPA for clean-up costs incurred and to be incurred by the agency and
for the costs of implementing an EPA-mandated remedy. The EPA’s
claims are based on ACE’s sale of boiler slag from the B.L. England generating
facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983
(ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag
Pile Site). EPA further claims that the boiler slag ACE sold to MDC
contained copper and lead, which are hazardous substances under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
(CERCLA), and that the sales transactions may have constituted an arrangement
for the disposal or treatment of hazardous substances at the site, which could
be a basis for liability under
355
ACE
CERCLA. The
EPA’s letter also states that to date its expenditures for response measures at
the site exceed $6 million. EPA estimates approximately
$6 million as the cost for future response measures it
recommends. ACE understands that the EPA sent similar general notice
letters to three other companies and various individuals.
ACE believes that the B.L. England
boiler slag sold to MDC was a valuable material with various industrial
applications, and therefore, such sale was not an arrangement for the disposal
or treatment of any hazardous substances as would be necessary to constitute a
basis for liability under CERCLA. ACE intends to contest any
such claims made by the EPA. At this time ACE cannot predict how EPA
will proceed or what portion, if any, of the Franklin Slag Pile Site response
costs EPA would seek to recover from ACE.
Appeal of New Jersey Flood Hazard
Regulations. In November 2007, NJDEP adopted amendments to the
agency’s 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, which took effect November 5, 2007,
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 filed an appeal of these
regulations with the Appellate Division of the Superior Court of New Jersey on
November 3, 2008. See Item I “Business – Environmental Matters–
Air Quality Regulation – Sulfur Dioxide, Nitrogen Oxide, Mercury and Nickel
Emissions.”
IRS
Mixed Service Cost Issue
During
2001, ACE changed its method of accounting with respect to capitalizable
construction costs for income tax purposes. The change allowed ACE to
accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $49
million for ACE, primarily attributable to ACE’s 2001 tax returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require ACE
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on those proposed regulations, PHI in its 2005 federal
tax return adopted an alternative method of accounting for capitalizable
construction costs that management believed would be acceptable to the Internal
Revenue Service (IRS).
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which was
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that ACE had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
Appeals Office of the IRS.
356
ACE
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. In June 2008, PHI
received from the IRS an offer of settlement pertaining to ACE for the tax years
2001 through 2004. ACE is substantially in agreement with this
proposed settlement. Based on the terms of the proposal, ACE expects
the final settlement amount to be less than the $121 million previously
deposited.
On the
basis of the tentative settlement, ACE updated its estimated liability related
to mixed service costs and, as a result, recorded in the quarter ended June 30,2008, a net reduction in its liability for unrecognized tax benefits of $2
million and recognized after-tax interest income of $2 million.
Contractual
Obligations
As of December 31, 2008, ACE’s
contractual obligations under non-derivative fuel and power purchase contracts
were $275 million in 2009, $ 500 million in 2010 to 2011, $461 million in 2012
to 2013, and $2,196 million in 2014 and thereafter.
(15) RELATED PARTY
TRANSACTIONS
PHI Service Company provides various
administrative and professional services to PHI and its regulated and
unregulated subsidiaries including ACE. The cost of these services is
allocated in accordance with cost allocation methodologies set forth in the
service agreement using a variety of factors, including the subsidiaries’ share
of employees, operating expenses, assets, and other cost causal
methods. These intercompany transactions are eliminated by PHI in
consolidation and no profit results from these transactions at
PHI. PHI Service Company costs directly charged or allocated to ACE
for the years ended December 31, 2008, 2007 and 2006 were $88 million, $81
million and $79 million, respectively.
In addition to the PHI Service Company
charges described above, ACE’s financial statements include the following
related party transactions in its Consolidated Statements of
Earnings:
As discussed in Note (14), “Commitments
and Contingencies,” herein, in February 2007, ACE completed the sale of the B.L.
England generating facility. B.L. England comprised a significant
component of ACE’s generation operations and its sale required discontinued
operations presentation under SFAS No. 144, “Accounting for the Impairment or
Disposal of Long Lived Assets,” on ACE’s Consolidated Statements of Earnings for
the years ended December 31, 2007 and 2006. In September 2006,
ACE sold its interests in the Keystone and Conemaugh generating facilities,
which for the year ended December 31, 2006 is also reflected as
discontinued operations.
The following table summarizes
information related to the discontinued operations presentation (millions of
dollars):
2008
2007
2006
Operating
Revenue
$ -
$10
$114
Income
Before Income Tax Expense
$ -
$ -
$ 4
Net
Income
$ -
$ -
$ 2
358
ACE
(17) QUARTERLY FINANCIAL
INFORMATION (UNAUDITED)
The quarterly data presented below
reflect all adjustments necessary in the opinion of management for a fair
presentation of the interim results. Quarterly data normally vary
seasonally because of temperature variations, differences between summer and
winter rates, and the scheduled downtime and maintenance of electric generating
units. Therefore, comparisons by quarter within a year are not
meaningful.
2008
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$361
$387
$540
$345
$1,633
Total
Operating Expenses
346
330
494
(c)
310
1,480
Operating
Income
15
57
46
35
153
Other
Expenses
(13)
(14)
(13)
(19)
(59)
Income
Before Income Tax Expense
2
43
33
16
94
Income
Tax Expense
(3)
(a)
16
(b)
13
4
(d)
30
Income
From Continuing Operations
5
27
20
12
64
Discontinued
Operations, net of tax
-
-
-
-
-
Net
Income
5
27
20
12
64
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$ 5
$
27
$
20
$
12
$ 64
2007
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Millions
of dollars)
Total
Operating Revenue
$338
$339
$505
$361
$1,543
Total
Operating Expenses
312
292
(e)
449
(e)
331
(e)
1,384
Operating
Income
26
47
56
30
159
Other
Expenses
(14)
(15)
(15)
(14)
(58)
Income
Before Income Tax Expense
12
32
41
16
101
Income
Tax Expense
4
13
15
9
41
Income
From Continuing Operations
8
19
26
7
60
Discontinued
Operations, net of tax
-
-
-
-
-
Net
Income
8
19
26
7
60
Dividends
on Preferred Stock
-
-
-
-
-
Earnings
Available for Common Stock
$ 8
$ 19
$ 26
$ 7
$ 60
(a)
Includes
$4 million of after-tax net interest income on uncertain tax positions
primarily related to casualty
losses.
(b)
Includes
$2 million of after-tax interest income related to the tentative
settlement of the IRS mixed service cost
issue.
(c)
Includes
a $1 million charge related to an adjustment in the accounting for certain
restricted stock awards granted under the Long-Term Incentive Plan
(LTIP).
(d)
Includes
$8 million of after-tax net interest income on uncertain and effectively
settled tax positions (primarily associated with a claim made with the IRS
related to the tax reporting for fuel over- and under-recoveries, certain
newly identified overpayments of income taxes in previously filed tax
returns and the reversal of the majority of the interest income recognized
on uncertain tax positions related to casualty losses in the first
quarter) and a charge of $7 million to correct prior period errors related
to additional analysis of deferred tax balances completed in
2008.
(e)
Includes
adjustment related to timing of recognition of certain operating expenses
which were overstated by $5 million in the fourth quarter and understated
by $1 million and $4 million in the second and third quarters,
respectively.
359
THIS
PAGE LEFT INTENTIONALLY BLANK.
360
Item
9.
CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None for all registrants.
Item
9A.
CONTROLS AND
PROCEDURES
Pepco Holdings,
Inc.
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, Pepco Holdings has evaluated the effectiveness of the design
and operation of its disclosure controls and procedures as of December 31, 2008,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of Pepco Holdings have concluded that these controls and
procedures are effective to provide reasonable assurance that material
information relating to Pepco Holdings and its subsidiaries that is required to
be disclosed in reports filed with, or submitted to, the Securities and Exchange
Commission (SEC) under the Securities Exchange Act of 1934, as amended (the
Exchange Act) (i) is recorded, processed, summarized and reported within the
time periods specified by the SEC rules and forms and (ii) is accumulated and
communicated to management, including its chief executive officer and chief
financial officer, as appropriate to allow timely decisions regarding required
disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal
Control over Financial Reporting” in Item 8 of this Form 10-K.
Attestation
Report of the Registered Public Accounting Firm
See “Report of Independent Registered
Public Accounting Firm” in Item 8 of this Form 10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,2008, there was no change in Pepco Holdings’ internal control over financial
reporting that has materially affected, or is reasonably likely to materially
affect, Pepco Holdings’ internal controls over financial reporting.
Item
9A(T). CONTROLS AND
PROCEDURES
Potomac Electric Power
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, Pepco has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2008,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of Pepco have concluded that these controls and procedures are
effective to provide reasonable assurance
361
that
material information relating to Pepco that is required to be disclosed in
reports filed with, or submitted to, the SEC under the Exchange Act (i) is
recorded, processed, summarized and reported within the time periods specified
by the SEC rules and forms and (ii) is accumulated and communicated to
management, including its chief executive officer and chief financial officer,
as appropriate to allow timely decisions regarding required
disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal
Control over Financial Reporting” in Item 8 of this Form 10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,2008, there was no change in Pepco’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
Pepco’s internal controls over financial reporting.
Delmarva Power & Light
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, DPL has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2008,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of DPL have concluded that these controls and procedures are
effective to provide reasonable assurance that material information relating to
DPL that is required to be disclosed in reports filed with, or submitted to, the
SEC under the Exchange Act (i) is recorded, processed, summarized and reported
within the time periods specified by the SEC rules and forms and (ii) is
accumulated and communicated to management, including its chief executive
officer and chief financial officer, as appropriate to allow timely decisions
regarding required disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal
Control over Financial Reporting” in Item 8 of this Form 10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,2008, there was no change in DPL’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
DPL’s internal controls over financial reporting.
Atlantic City Electric
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, ACE has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2008,
and,
362
based
upon this evaluation, the chief executive officer and the chief financial
officer of ACE have concluded that these controls and procedures are effective
to provide reasonable assurance that material information relating to ACE and
its subsidiaries that is required to be disclosed in reports filed with, or
submitted to, the SEC under the Exchange Act (i) is recorded, processed,
summarized and reported within the time periods specified by the SEC rules and
forms and (ii) is accumulated and communicated to management, including its
chief executive officer and chief financial officer, as appropriate to allow
timely decisions regarding required disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Report on Internal
Control over Financial Reporting” in Item 8 of this Form 10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,2008, there was no change in ACE’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
ACE’s internal controls over financial reporting.
Item
9B. OTHER
INFORMATION
Pepco Holdings,
Inc.
None.
Potomac Electric Power
Company
None.
Delmarva Power & Light
Company
None
Atlantic City Electric
Company
None
363
Part III
Item
10. DIRECTORS, EXECUTIVE
OFFICERS AND CORPORATE GOVERNANCE
Pepco Holdings,
Inc.
The following information appearing in
PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected
to be filed with the SEC on or about March 26, 2009, is incorporated herein by
reference:
·
The
information appearing under the heading “Nominees for Election as
Directors.”
·
The
information appearing under the heading “Security Ownership of Certain
Beneficial Owners and Management — Section 16(a) Beneficial Ownership
Reporting Compliance.”
·
The
information appearing under the heading “Where do I find the Company’s
Corporate Business Policies, Corporate Governance Guidelines and Committee
Charters?” concerning PHI’s Corporate Business
Policies.
·
The
information appearing under the heading “Board Committees — Audit
Committee,” regarding the membership and function of the Audit Committee
and the financial expertise of its
members.
Executive Officers of
PHI
The names of the executive officers of
PHI and their ages and the positions they held as of March 1, 2009, are set
forth in the following table. Their business experience during the
past five years is set forth in the footnotes to the table.
PEPCO HOLDINGS
Name
Age
Office and
Length of Service
Dennis
R. Wraase
64
Chairman
of the Board
5/04
- Present
(1)
William
T. Torgerson
64
Vice Chairman - 6/03
- Present and Chief Legal
Officer
3/08
- Present (2)
Joseph
M. Rigby
52
President - 3/08 - Present and Chief Executive
Officer
3/09
- Present
(3)
David
M. Velazquez
49
Executive
Vice President
3/09
- Present (4)
Paul
H. Barry
51
Senior
Vice President and Chief Financial Officer
9/07
- Present
(5)
364
Kirk
J. Emge
59
Senior
Vice President and General Counsel
3/08
- Present
(6)
Anthony
J. Kamerick
61
Senior
Vice President and Chief Regulatory Officer
3/09
- Present (7)
Beverly
L. Perry
61
Senior
Vice President
10/02
-
Present
Ronald
K. Clark
53
Vice
President and Controller
8/05
- Present
(8)
Gary
J. Morsches
49
President
and Chief Executive Officer, Conectiv Energy Holding Company
3/09
- Present (9)
John
U. Huffman
49
President - 6/06 - Present and Chief Executive Officer,
Pepco Energy Services, Inc. - 3/09 - Present
(10)
(1)
Mr.
Wraase was Chief Executive Officer of PHI from May 2004 until February 28,2009, President of PHI from August 2002 until March 2008 and Chief
Operating Officer of PHI from August 2002 until June
2003. Mr. Wraase was Chairman of Pepco from May 2004 until
February 28, 2009 and was Chief Executive Officer from August 2002 until
October 2005. From May 2004 to February 28, 2009, he was also
Chairman of DPL and ACE.
(2)
Mr.
Torgerson was General Counsel of PHI from August 2002 until March
2008.
(3)
Mr.
Rigby was Chief Operating Officer of PHI from September 2007 until
February 28, 2009 and Executive Vice President of PHI from September
2007 until March 2008, Senior Vice President of PHI from August 2002 until
September 2007 and Chief Financial Officer of PHI from May 2004 until
September 2007. Mr. Rigby was President of ACE from July
2001 until May 2004 and Chief Executive Officer of ACE from August 2002
until May 2004. He served as President of DPL from August 2002
until May 2004. Mr. Rigby was President and Chief Executive
Officer of ACE, DPL and Pepco from September 1, 2007 to February 28,2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE
since March 1, 2009.
(4)
Mr.
Velazquez served as President of Conectiv Energy Holding Company, an
affiliate of PHI, from June 2006 to February 28, 2009, Chief
Executive Officer of Conectiv Energy Holding Company from January 2007 to
February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding
Company from June 2006 to December 2006. He served as a Vice
President of PHI from February 2005 to June 2006 and as Chief Risk Officer
of PHI from August 2005 to June 2006. From July 2001 to
February 2005, he served as a Vice President of Conectiv Energy Supply,
Inc., an affiliate of PHI.
365
(5)
Mr.
Barry was Senior Vice President and Chief Development Officer of Duke
Energy Corporation from September 2006 to August 2007. From
November 2005 to September 2006, he was Group Executive and President of
Duke Energy Americas, a division of Duke Energy
Corporation. From June 2002 to November 2005, he was a Vice
President of Duke Energy Corporation. Duke Energy is an energy
company not affiliated with PHI.
(6)
Mr.
Emge was Vice President, Legal Services from August 2002 until March
2008. Mr. Emge has served as General Counsel of ACE, DPL and
Pepco since August 2002 and as Senior Vice President of Pepco and DPL
since March 1, 2009.
(7)
Mr.
Kamerick was Vice President and Treasurer of PHI from August 2002 until
February 28, 2009.
(8)
Mr.
Clark has been employed by PHI since June 2005 and has also served as Vice
President and Controller of Pepco and DPL and Controller of ACE since
August 2005. From July 2004 until June 2005, he was Vice
President, Financial Reporting and Policy for MCI, Inc., a
telecommunications company not affiliated with
PHI.
(9)
Mr.
Morsches was Executive Vice President of Conectiv Energy Supply, Inc. from
January 2009 until February 28, 2009. Mr. Morsches was a
Principal of the Boston Consulting Group, a management consulting firm,
which is not affiliated with PHI, from June 2005 until January 2009 and
was a self-employed consultant from January 2003 until June
2005.
(10)
Since
June 2003, Mr. Huffman has been employed by Pepco Energy Services in the
following capacities: (a) Chief Operating Officer from April
2006 to February 28, 2009, (b) Senior Vice President, February 2005
to March 2006 and (c) Vice President from June 2003 to February
2005.
The PHI executive officers are elected
annually and serve until their respective successors have been elected and
qualified or their earlier resignation or removal.
INFORMATION FOR THIS ITEM IS NOT
REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN
GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS
FORM WITH THE REDUCED FILING FORMAT.
Item
11. EXECUTIVE
COMPENSATION
Pepco Holdings,
Inc.
The
following information appearing in PHI’s definitive proxy statement for the 2009
Annual Meeting, which is expected to be filed with the SEC on or about March 26,2009, is incorporated herein by reference:
·
The
information appearing under the heading “2008 Director
Compensation.”
·
The
information appearing under the heading “Compensation Discussion and
Analysis.”
366
·
The
information appearing under the heading “Executive
Compensation.”
·
The
information appearing under the heading “Compensation/Human Resources
Committee Report.”
INFORMATION FOR THIS ITEM IS NOT
REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN
GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS
FORM WITH THE REDUCED FILING FORMAT.
Item
12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Pepco Holdings,
Inc.
The information appearing under the
heading “Security Ownership of Certain Beneficial Owners and Management” in
PHI’s definitive proxy statement for the 2009 Annual Meeting, which is expected
to be filed with the SEC on or about March 26, 2009, is incorporated herein by
reference.
The following table provides
information as of December 31, 2008, with respect to the shares of PHI’s common
stock that may be issued under PHI’s existing equity compensation
plans.
Equity
Compensation Plans Information
Plan
Category
Number
of Securities to be Issued Upon Exercise of Outstanding
Options
Weighted-Average
Exercise Price of Outstanding Options
Number
of Securities Remaining Available for Future Issuance Under Equity
Compensation Plans (Excluding Outstanding Options)
Equity
Compensation Plans Approved by Shareholders (a)
(b)
(b)
8,473,554
Equity
Compensation Plans Not Approved by Shareholders
-
-
488,713 (c)
Total
-
-
8,962,267
(a)
Consists
solely of the Pepco Holdings, Inc. Long-Term Incentive
Plan.
(b)
In
connection with the acquisition by Pepco of Conectiv (i) outstanding
options granted under the Potomac Electric Power Company Long-Term
Incentive Plan were converted into options to purchase shares of PHI
common stock and (ii) options granted under the Conectiv Incentive
Compensation Plan were converted into options to purchase shares of PHI
common stock. As of December 31, 2008, options to purchase
an aggregate of 374,904 shares of PHI common stock, having a weighted
average exercise price of $22.2647, were
outstanding.
(c)
Consists
of shares of PHI common stock available for future issuance under the PHI
Non-Management Directors Compensation Plan. Under this plan,
each director who is not an employee of PHI or any of its subsidiaries
(“non-management director”) is entitled to elect to receive his or her
annual retainer, retainer for service as a committee chairman, if any, and
meeting fees in: (i) cash, (ii) shares of PHI’s common stock,
(iii) a credit to an account for the director established under PHI’s
Executive and Director Deferred Compensation Plan or (iv) any combination
thereof. The plan expires on December 31, 2014 unless
terminated earlier by the Board of
Directors.
367
INFORMATION FOR THIS ITEM IS NOT
REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN
GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS
FORM WITH THE REDUCED FILING FORMAT.
Item
13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pepco Holdings,
Inc.
The
information appearing under the heading “Board Review of Transactions With
Related Parties” in PHI’s definitive proxy statement for the 2009 Annual
Meeting, which is expected to be filed with the SEC on or about March 26, 2009,
is incorporated herein by reference.
INFORMATION FOR THIS ITEM IS NOT
REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM
WITH THE REDUCED FILING FORMAT.
Item
14. PRINCIPAL ACCOUNTANT FEES
AND SERVICES
Pepco Holdings, Inc., Pepco,
DPL and ACE
Audit
Fees
The
aggregate fees billed by PricewaterhouseCoopers LLP for professional services
rendered for the audit of the annual financial statements of Pepco Holdings and
its subsidiary reporting companies for the 2008 and 2007 fiscal years, reviews
of the financial statements included in the 2008 and 2007 Forms 10-Q of Pepco
Holdings and its subsidiary reporting companies, reviews of public filings,
comfort letters and other attest services were $7,780,994 and $6,143,733,
respectively. The amount for 2007 includes $69,325 for the 2007 audit
that was billed after the 2007 amount was disclosed in Pepco Holding’s proxy
statement for the 2008 Annual Meeting.
Audit-Related
Fees
No fees were billed by
PricewaterhouseCoopers LLP for audit-related services for the 2008 or 2007
fiscal years.
Tax
Fees
The aggregate fees billed by
PricewaterhouseCoopers LLP for tax services rendered for the 2008 and 2007
fiscal years were $284,678 and $126,810 respectively. These services consisted
of tax compliance, tax advice and tax planning.
All
Other Fees
The aggregate fees billed by
PricewaterhouseCoopers LLP for all other services other than those covered under
“Audit Fees,”“Audit-Related Fees” and “Tax Fees” for the 2008 and
368
2007
fiscal years were $4,500 and $41,740, respectively, which represented the costs
of training and technical materials provided by PricewaterhouseCoopers
LLP.
All of the services described in “Audit
Fees,”“Audit-Related Fees,”“Tax Fees” and “All Other Fees” were approved in
advance by the Audit Committee, in accordance with the Audit Committee Policy on
the Approval of Services Provided by the Independent Auditor which is attached
as Annex A to Pepco Holdings’ definitive proxy statement for the 2009 Annual
Meeting of Shareholders to be filed with the SEC on or about March 26, 2009, and
is incorporated herein by reference.
Part IV
Item
15. EXHIBITS AND FINANCIAL
STATEMENT SCHEDULES
(a) Documents
List
1. FINANCIAL
STATEMENTS
The financial statements filed as part
of this report consist of the financial statements of each registrant set forth
in Item 8, “Financial Statements and Supplementary Data” of this Form
10-K.
2. FINANCIAL STATEMENT
SCHEDULES
The financial statement schedules
specified by Regulation S-X, other than those listed below, are omitted because
either they are not applicable or the required information is presented in the
financial statements included in Item 8, “Financial Statements and Supplementary
Data” of this Form 10-K.
Registrants
Item
Pepco
Holdings
Pepco
DPL
ACE
Schedule
I, Condensed Financial
Information
of Parent Company
370
N/A
N/A
N/A
Schedule
II, Valuation and
Qualifying
Accounts
373
373
374
374
369
Schedule I, Condensed Financial
Information of Parent Company is submitted below.
Common
stock issued to the Dividend Reinvestment Plan
29
28
30
Issuance
of common stock
287
200
17
Issuance
of long-term debt
-
450
200
Capital
distribution to subsidiaries
(175)
-
-
Reacquisition
of long-term debt
-
(500)
(300)
Decrease
in notes receivable from
associated companies
79
227
203
Issuances
(repayments) of short-term debt, net
50
(36)
36
Costs
of issuances and refinancings
(10)
(3)
(2)
Other
financing activities
-
-
(1)
Net
Cash From (Used By) Financing Activities
38
163
(15)
Net
change in cash and cash equivalents
169
291
53
Beginning
of year cash and cash equivalents
387
96
43
End
of year cash and cash equivalents
$556
$387
$ 96
The
accompanying Notes are an integral part of these financial
statements.
NOTES
TO FINANCIAL INFORMATION
These
condensed financial statements represent the financial information for Pepco
Holdings, Inc. (Parent Company).
For
information concerning PHI’s long-term debt obligations, see Note (11), “Debt”
to the consolidated financial statements of Pepco Holdings included in Item 8 of
this Form 10-K.
For
information concerning PHI’s material contingencies and guarantees, see Note
(16), “Commitments and Contingencies” to the consolidated financial statements
of Pepco Holdings included in Item 8 of this Form 10-K.
The
Parent Company’s majority owned subsidiaries are recorded using the equity
method of accounting.
372
Schedule II (Valuation and Qualifying
Accounts) for each registrant is submitted below:
(a) Collection
of accounts previously written off.
(b) Uncollectible
accounts written off.
374
3. EXHIBITS
The documents listed below are being
filed herewith or have previously been filed and are incorporated herein by
reference from the documents indicated and made a part hereof.
Exhibit
No.
Registrant(s)
Description of Exhibit
Reference
3.1
PHI
Restated
Certificate of Incorporation (filed in Delaware 6/2/2005)
Exh.
3.1 to PHI’s Form 10-K, 3/13/06.
3.2
Pepco
Restated
Articles of Incorporation and Articles of Restatement (as filed in the
District of Columbia)
Exh.
3.1 to Pepco’s Form 10-Q, 5/5/06.
3.3
DPL
Articles
of Restatement of Certificate and Articles of Incorporation (filed in
Delaware and Virginia 02/22/07)
Exh.
3.3 to DPL’s Form 10-K, 3/1/07.
3.4
ACE
Restated
Certificate of Incorporation (filed in New Jersey 8/09/02)
Exh.
B.8.1 to PHI’s Amendment No. 1 to Form U5B, 2/13/03.
3.5
PHI
Bylaws
Exh.
3 to PHI’s Form 8-K, 5/3/07.
3.6
Pepco
By-Laws
Exh.
3.1 to Pepco’s Form 10-Q, 5/5/06.
3.7
DPL
Bylaws
Exh.
3.2.1 to DPL’s Form 10-Q 5/9/05.
3.8
ACE
Bylaws
Exh.
3.2.2 to ACE’s Form 10-Q 5/9/05.
4.1
PHI
Pepco
Mortgage
and Deed of Trust dated July 1, 1936, of Pepco to The Bank of New
York Mellon as successor trustee, securing First Mortgage Bonds of Pepco,
and Supplemental Indenture dated July 1, 1936
Exh.
B-4 to First Amendment, 6/19/36, to Pepco’s Registration Statement No.
2-2232.
Supplemental
Indentures, to the aforesaid Mortgage and Deed of Trust, dated
-
December
10, 1939
Exh.
B to Pepco’s Form 8-K, 1/3/40.
July
15, 1942
Exh.
B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment,
8/31/42, to Pepco’s Registration Statement No.
2-5032.
375
October
15, 1947
Exh.
A to Pepco’s Form 8-K, 12/8/47.
December
31, 1948
Exh.
A-2 to Pepco’s Form 10-K, 4/13/49.
December
31, 1949
Exh.
(a)-1 to Pepco’s Form 8-K, 2/8/50.
February
15, 1951
Exh.
(a) to Pepco’s Form 8-K, 3/9/51.
February
16, 1953
Exh.
(a)-1 to Pepco’s Form 8-K, 3/5/53.
March
15, 1954 and March 15, 1955
Exh.
4-B to Pepco’s Registration Statement No. 2-11627,
5/2/55.
March
15, 1956
Exh.
C to Pepco’s Form 10-K, 4/4/56.
April
1, 1957
Exh.
4-B to Pepco’s Registration Statement No. 2-13884,
2/5/58.
May
1, 1958
Exh.
2-B to Pepco’s Registration Statement No. 2-14518,
11/10/58.
May
1, 1959
Exh.
4-B to Amendment No. 1, 5/13/59, to Pepco’s Registration Statement No.
2-15027.
May
2, 1960
Exh.
2-B to Pepco’s Registration Statement No. 2-17286,
11/9/60.
April
3, 1961
Exh.
A-1 to Pepco’s Form 10-K, 4/24/61.
May
1, 1962
Exh.
2-B to Pepco’s Registration Statement No. 2-21037,
1/25/63.
May
1, 1963
Exh.
4-B to Pepco’s Registration Statement No. 2-21961,
12/19/63.
April
23, 1964
Exh.
2-B to Pepco’s Registration Statement No. 2-22344,
4/24/64.
376
May
3, 1965
Exh.
2-B to Pepco’s Registration Statement No. 2-24655,
3/16/66.
June
1, 1966
Exh.
1 to Pepco’s Form 10-K, 4/11/67.
April
28, 1967
Exh.
2-B to Post-Effective Amendment No. 1 to Pepco’s Registration Statement
No. 2-26356, 5/3/67.
July
3, 1967
Exh.
2-B to Pepco’s Registration Statement No. 2-28080,
1/25/68.
May
1, 1968
Exh.
2-B to Pepco’s Registration Statement No. 2-31896,
2/28/69.
June
16, 1969
Exh.
2-B to Pepco’s Registration Statement No. 2-36094,
1/27/70.
May
15, 1970
Exh.
2-B to Pepco’s Registration Statement No. 2-38038,
7/27/70.
September
1, 1971
Exh.
2-C to Pepco’s Registration Statement No. 2-45591,
9/1/72.
June
17, 1981
Exh.
2 to Amendment No. 1 to Pepco’s Form 8-A, 6/18/81.
November
1, 1985
Exh.
2B to Pepco’s Form 8-A, 11/1/85.
September
16, 1987
Exh.
4-B to Pepco’s Registration Statement No. 33-18229,
10/30/87.
May
1, 1989
Exh.
4-C to Pepco’s Registration Statement No. 33-29382,
6/16/89.
Indenture,
dated as of July 28, 1989, between Pepco and The Bank of New York Mellon,
Trustee, with respect to Pepco’s Medium-Term Note Program
Exh.
4 to Pepco’s Form 8-K, 6/21/90.
4.3
PHI
Pepco
Senior
Note Indenture dated November 17, 2003 between Pepco and The Bank of
New York Mellon
Exh.
4.2 to Pepco’s Form 8-K, 11/21/03.
Supplemental
Indenture, to the aforesaid Senior Note Indenture, dated March 3,2008
Filed
herewith.
378
4.4
PHI
DPL
Mortgage
and Deed of Trust of Delaware Power & Light Company to The Bank of New
York Mellon (ultimate successor to the New York Trust Company), as
trustee, dated as of October 1, 1943 and copies of the First through
Sixty-Eighth Supplemental Indentures thereto
Exh.
4-A to DPL’s Registration Statement No. 33-1763,
11/27/85.
Sixty-Ninth
Supplemental Indenture
Exh.
4-B to DPL’s Registration Statement No. 33-39756,
4/03/91.
Seventieth
through Seventy-Fourth Supplemental Indentures
Exhs.
4-B to DPL’s Registration Statement No. 33-24955,
10/13/88.
Seventy-Fifth
through Seventy-Seventh Supplemental Indentures
Exh.
4-K to DPL’s Post Effective Amendment No. 1 to Registration Statement No.
333-145691-02, 11/18/08
4.5
PHI
DPL
Indenture
between DPL and The Bank of New York Mellon Trust Company, N.A. (ultimate
successor to Manufacturers Hanover Trust Company), as trustee, dated as of
November 1, 1988
Exh.
No. 4-G to DPL’s Registration Statement No. 33-46892,
4/1/92.
4.6
PHI
ACE
Mortgage
and Deed of Trust, dated January 15, 1937, between Atlantic City Electric
Company and The Bank of New York Mellon (formerly Irving Trust Company),
as trustee
Exh.
2(a) to ACE’s Registration Statement No. 2-66280,
12/21/79.
Supplemental
Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of
-
June
1, 1949
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
July
1, 1950
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
November
1, 1950
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
March
1, 1952
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
January
1, 1953
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
March
1, 1954
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
March
1, 1955
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
380
January
1, 1957
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
April
1, 1958
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
April
1, 1959
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
March
1, 1961
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
July
1, 1962
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
March
1, 1963
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
February
1, 1966
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
April
1, 1970
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
September
1, 1970
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
May
1, 1971
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
April
1, 1972
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
June
1, 1973
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
January
1, 1975
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
381
May
1, 1975
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
December
1, 1976
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
January
1, 1980
Exh.
4(e) to ACE’s Form 10-K, 3/25/81.
May
1, 1981
Exh.
4(a) to ACE’s Form 10-Q, 8/10/81.
November
1, 1983
Exh.
4(d) to ACE’s Form 10-K, 3/30/84.
April
15, 1984
Exh.
4(a) to ACE’s Form 10-Q, 5/14/84.
July
15, 1984
Exh.
4(a) to ACE’s Form 10-Q, 8/13/84.
October
1, 1985
Exh.
4 to ACE’s Form 10-Q, 11/12/85.
May
1, 1986
Exh.
4 to ACE’s Form 10-Q, 5/12/86.
July
15, 1987
Exh.
4(d) to ACE’s Form 10-K, 3/28/88.
October
1, 1989
Exh.
4(a) to ACE’s Form 10-Q for quarter ended 9/30/89.
Indenture
dated as of March 1, 1997 between Atlantic City Electric Company and The
Bank of New York Mellon, as trustee
Exh.
4(e) to ACE’s Form 8-K, 3/24/97.
4.8
PHI
ACE
Senior
Note Indenture, dated as of April 1, 2004, with The Bank of New York
Mellon, as trustee
Exh.
4.2 to ACE’s Form 8-K, 4/6/04.
4.9
PHI
ACE
Indenture
dated as of December 19, 2002 between Atlantic City Electric
Transition Funding LLC (ACE Funding) and The Bank of New York Mellon, as
trustee
Exh.
4.1 to ACE Funding’s Form 8-K, 12/23/02.
4.10
PHI
ACE
2002-1
Series Supplement dated as of December 19, 2002 between ACE Funding
and The Bank of New York Mellon, as trustee
Exh.
4.2 to ACE Funding’s Form 8-K, 12/23/02.
4.11
PHI
ACE
2003-1
Series Supplement dated as of December 23, 2003 between ACE Funding
and The Bank of New York Mellon, as trustee
Exh.
4.2 to ACE Funding’s Form 8-K, 12/23/03.
4.12
PHI
Indenture
between PHI and The Bank of New York Mellon, as trustee dated September 6,2002
Exh.
4.03 to PHI’s Registration Statement No. 333-100478,
10/10/02.
383
10.1
PHI
Employment
Agreement of Dennis R. Wraase dated July 26, 2007*
Exh.
10.3 to PHI’s Form 10-Q, 8/6/07.
10.2
PHI
Employment
Agreement of William T. Torgerson dated August 1,2002*
Exh.
10.3 to PHI’s Form 10-Q, 8/9/02.
10.3
PHI
Employment
Agreement of Paul H. Barry dated August 7, 2007*
Form
of Election with Respect to Stock Tax Withholding*
Exh.
10.8 to PHI’s Form 10-Q, 11/8/04.
10.21
PHI
Non-Management
Directors Compensation Plan*
Filed
herewith.
10.22
PHI
Annual
Executive Incentive Compensation Plan dated as of February 9,2009*
Filed
herewith.
10.23
PHI
Non-Management
Director Compensation Arrangements*
Exh.
10-24 to PHI’s Form 10-K, 2/29/08.
10.24
PHI
Form
of Election regarding Non-Management Directors Compensation
Plan*
Exh.
10.57 to PHI’s Form 10-K, 3/16/05.
10.25
PHI
Pepco
Change-in-Control
Severance Plan for Certain Executive Employees*
Filed
herewith.
10.26
PHI
Pepco
PHI
Named Executive Officer 2007 Compensation Determinations*
Exh.
10.32 to PHI’s Form 10-K, 2/29/08.
10.27
PHI
Pepco
DPL
ACE
Amended
and Restated Credit Agreement, dated as of May 2, 2007, between PHI,
Pepco, DPL and ACE, the lenders party thereto, Wachovia Bank, National
Association, as administrative agent and swingline lender, Citicorp USA,
Inc., as syndication agent, The Royal Bank of Scotland, plc, The Bank of
Nova Scotia and JPMorgan Chase Bank, N.A., as documentation agents, and
Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as joint
lead arrangers and joint book runners
Exh.
10 to PHI’s Form 10-Q, 5/7/07.
10.28
PHI
Pepco
Holdings, Inc. Combined Executive Retirement Plan*
Filed
herewith.
10.29
PHI
PHI
Named Executive Officer 2008 Compensation Determinations*
Exh.
10.33 to PHI’s Form 10-K, 2/29/08.
10.30
PHI
PHI
Named Executive Officer 2009 Compensation Determinations*
Filed
herewith.
385
10.31
DPL
Transmission
Purchase and Sale Agreement By and Between Delmarva Power & Light
Company and Old Dominion Electric Cooperative dated as of June 13,2007
Exh.
10.1 to DPL’s Form 10-Q, 8/6/07.
10.32
DPL
Purchase
And Sale Agreement By and Between Delmarva Power & Light Company and
A&N Electric Cooperative dated as of June 13, 2007
Exh.
10.2 to DPL’s Form 10-Q, 8/6/07.
10.33
DPL
PHI
Loan
Agreement, dated as of March 20, 2008, between DPL and The Bank of Nova
Scotia
Exh.
10.1 to DPL’s Form 8-K, 3/24/08.
10.34
Pepco
PHI
Loan
Agreement, dated as of May 1, 2008, between Pepco and Wachovia Bank,
National Association
Exh.
10.1 to Pepco’s Form 8-K, 5/6/08.
10.35
PHI
Amendment
to Employment Agreement of Dennis R. Wraase effective August 1,2008*
Exh.
10.2 to PHI’s Form 8-K, 7/30/08.
10.36
PHI
Amendment
to Employment Agreement of William T. Torgerson effective August 1,2008*
Filed
herewith.
10.37
PHI
Credit
Agreement, dated November 7, 2008, by and among Bank of America, N.A.,
Banc of America Securities, KeyBank National Association, JPMorgan Chase
Bank, N.A., SunTrust Bank, The Bank of Nova Scotia, Morgan Stanley Bank,
Credit Suisse, Cayman Islands Branch and Wachovia Bank, National
Association
Filed
herewith.
11
PHI
Statements
Re: Computation of Earnings Per Common Share
**
12.1
PHI
Statements
Re: Computation of Ratios
Filed
herewith.
12.2
Pepco
Statements
Re: Computation of Ratios
Filed
herewith.
12.3
DPL
Statements
Re: Computation of Ratios
Filed
herewith.
12.4
ACE
Statements
Re: Computation of Ratios
Filed
herewith.
21
PHI
Subsidiaries
of the Registrant
Filed
herewith.
23.1
PHI
Consent
of Independent Registered Public Accounting Firm
Filed
herewith.
23.2
Pepco
Consent
of Independent Registered Public Accounting Firm
Filed
herewith.
386
23.3
DPL
Consent
of Independent Registered Public Accounting Firm
Filed
herewith.
23.4
ACE
Consent
of Independent Registered Public Accounting Firm
Filed
herewith.
31.1
PHI
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed
herewith.
31.2
PHI
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed
herewith.
31.3
Pepco
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed
herewith.
31.4
Pepco
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed
herewith.
31.5
DPL
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed
herewith.
31.6
DPL
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed
herewith.
31.7
ACE
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
Filed
herewith.
31.8
ACE
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
Filed
herewith.
* Management
contract or compensatory plan or arrangement.
** The
information required by this Exhibit is set forth in Note (14) of
the Financial Statements of Pepco Holdings included in Item 8 “Financial
Statements and Supplementary Data” of this Form 10-K.
Regulation S-K Item 10(d) requires
registrants to identify the physical location, by SEC file number reference, of
all documents incorporated by reference that are not included in a registration
statement and have been on file with the SEC for more than five
years. The SEC file number references for Pepco Holdings, Inc., those
of its subsidiaries that are registrants, Conectiv and ACE Funding are provided
below:
Delmarva Power & Light Company in
file number 001-1405
Atlantic City Electric Company in file
number 001-3559
Atlantic City Electric Transition
Funding LLC in file number 333-59558
Certain instruments defining the rights
of the holders of long-term debt of PHI, Pepco, DPL and ACE (including
medium-term notes, unsecured notes, senior notes and tax-exempt
387
financing
instruments) have not been filed as exhibits in accordance with Regulation S-K
Item 601(b)(4)(iii) because such instruments do not authorize securities in an
amount which exceeds 10% of the total assets of the applicable registrant and
its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or
ACE agrees to furnish to the SEC upon request a copy of any such instruments
omitted by it.
INDEX TO FURNISHED
EXHIBITS
The documents listed below are being
furnished herewith:
Exhibit No.
Registrant(s)
Description of Exhibit
32.1
PHI
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
32.2
Pepco
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
32.3
DPL
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
32.4
ACE
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statements on Form
S-3 (Nos. 333-145691 and 333-129429) and the Registration Statements on Form S-8
(Nos. 333-96675, 333-121823 and 333-131371) of Pepco Holdings, Inc. of our
report dated March 2, 2009 for Pepco Holdings, Inc. relating to the financial
statements, financial statement schedules and the effectiveness of internal
control over financial reporting, which appears in this Form 10-K.
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statement on Form
S-3 (No. 333-145691-03) of Potomac Electric Power Company of our report dated
March 2, 2009 relating to the financial statements and financial statement
schedule of Potomac Electric Power Company, which appears in this Form
10-K.
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statements on Form
S-3 (No. 333-145691-02) of Delmarva Power & Light Company of our report
dated March 2, 2009 relating to the financial statements and financial statement
schedule of Delmarva Power & Light Company, which appears in this Form
10-K.
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statement on Form
S-3 (No. 333-145691-01) of Atlantic City Electric Company of our report dated
March 2, 2009 relating to the financial statements and financial statement
schedule of Atlantic City Electric Company, which appears in this Form
10-K.
I
have reviewed this report on Form 10-K of Pepco Holdings,
Inc.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Pepco Holdings,
Inc.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Potomac Electric Power
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Potomac Electric Power
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Delmarva Power & Light
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Delmarva Power & Light
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Atlantic City Electric
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
I
have reviewed this report on Form 10-K of Atlantic City Electric
Company.
2.
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3.
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
4.
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
b)
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
c)
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
d)
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
5.
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
a)
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
b)
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
Certificate
of Chief Executive Officer and Chief Financial Officer
of
Pepco
Holdings, Inc.
(pursuant
to 18 U.S.C. Section 1350)
I, Joseph M. Rigby, and I, Paul H.
Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of
Pepco Holdings, Inc. for the year ended December 31, 2008, filed with the
Securities and Exchange Commission on the date hereof fully complies with the
requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934,
as amended, and (ii) the information contained therein fairly presents, in all
material respects, the financial condition and results of operations of Pepco
Holdings, Inc.
A signed original of this written
statement required by Section 906 has been provided to Pepco Holdings, Inc. and
will be retained by Pepco Holdings, Inc. and furnished to the Securities and
Exchange Commission or its staff upon request.
Certificate
of Chief Executive Officer and Chief Financial Officer
of
Potomac
Electric Power Company
(pursuant
to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H.
Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of
Potomac Electric Power Company for the year ended December 31, 2008, filed with
the Securities and Exchange Commission on the date hereof fully
complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended, and (ii) the information contained therein
fairly presents, in all material respects, the financial condition and results
of operations of Potomac Electric Power Company.
A signed original of this written
statement required by Section 906 has been provided to Potomac Electric Power
Company and will be retained by Potomac Electric Power Company and furnished to
the Securities and Exchange Commission or its staff upon request.
Certificate
of Chief Executive Officer and Chief Financial Officer
of
Delmarva
Power & Light Company
(pursuant
to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H.
Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of
Delmarva Power & Light Company for the year ended December 31, 2008,
filed with the Securities and Exchange Commission on the date
hereof fully complies with the requirements of section 13(a) or 15(d)
of the Securities Exchange Act of 1934, as amended, and (ii) the information
contained therein fairly presents, in all material respects, the financial
condition and results of operations of Delmarva Power & Light
Company.
A signed original of this written
statement required by Section 906 has been provided to Delmarva Power &
Light Company and will be retained by Delmarva Power & Light Company and
furnished to the Securities and Exchange Commission or its staff upon
request.
Certificate
of Chief Executive Officer and Chief Financial Officer
of
Atlantic
City Electric Company
(pursuant
to 18 U.S.C. Section 1350)
I, David M. Velazquez, and I, Paul H.
Barry, certify that, to the best of my knowledge, (i) the Report on Form 10-K of
Atlantic City Electric Company for the year ended December 31, 2008, filed with
the Securities and Exchange Commission on the date hereof fully
complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended, and (ii) the information contained therein
fairly presents, in all material respects, the financial condition and results
of operations of Atlantic City Electric Company.
A signed original of this written
statement required by Section 906 has been provided to Atlantic City Electric
Company and will be retained by Atlantic City Electric Company and furnished to
the Securities and Exchange Commission or its staff upon request.
410
SIGNATURES
Pursuant to the requirements of Section
13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Pursuant to the requirements of the
Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the above named registrants and in the capacities
and on the dates indicated:
Supplemental
Indenture, to the aforesaid Senior Note Indenture, dated March 3,2008
10.5
PHI
Pepco
Holdings, Inc. Long-Term Incentive Plan*
10.6
PHI
Pepco
Holdings, Inc. Executive and Director Deferred Compensation
Plan*
10.10
PHI
Conectiv
Supplemental Executive Retirement Plan*
10.21
PHI
Non-Management
Directors Compensation Plan*
10.22
PHI
Annual
Executive Incentive Compensation Plan dated as of February 9,2009*
10.25
PHI,
Pepco
Change-In-Control
Severance Plan For Certain Executive Employees*
10.28
PHI
Pepco
Holdings, Inc. Combined Executive Retirement Plan*
10.30
PHI
PHI
Named Executive Officer 2009 Compensation
Determinations*
10.36
PHI
Amendment
to Employment Agreement of William T. Torgerson effective August 1,2008
10.37
PHI
Credit
Agreement, dated November 7, 2008, by and among Bank of America, N.A.,
Banc of America Securities, Key Bank National Association, JP Morgan Chase
Bank, N.A., Sun Trust Bank, The Bank of Nova Scotia, Morgan Stanley Bank,
Credit Suisse, Cayman Islands Branch and Wachovia Bank, National
Association
12.1
PHI
Statements
Re: Computation of Ratios
12.2
Pepco
Statements
Re: Computation of Ratios
12.3
DPL
Statements
Re: Computation of Ratios
12.4
ACE
Statements
Re: Computation of Ratios
21
PHI
Subsidiaries
of the Registrant
23.1
PHI
Consent
of Independent Registered Public Accounting Firm
23.2
Pepco
Consent
of Independent Registered Public Accounting Firm
23.3
DPL
Consent
of Independent Registered Public Accounting Firm
23.4
ACE
Consent
of Independent Registered Public Accounting Firm
31.1
PHI
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
31.2
PHI
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
31.3
Pepco
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
31.4
Pepco
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
31.5
DPL
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
31.6
DPL
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
31.7
ACE
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
31.8
ACE
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer