UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
DC 20549
FORM
10-K
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
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For
the Fiscal Year Ended December 31, 2006
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OR
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¨
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
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For
the Transition Period from to
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Commission
File Number
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Registrant,
State of Incorporation,
Address
and Telephone Number
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I.R.S.
Employer
Identification No.
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1-8809
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SCANA
Corporation
(a
South Carolina corporation)
1426
Main Street, Columbia, South Carolina 29201
(803) 217-9000
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57-0784499
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1-3375
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South
Carolina Electric & Gas Company
(a
South Carolina corporation)
1426
Main Street, Columbia, South Carolina 29201
(803) 217-9000
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57-0248695
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Securities
registered pursuant to Section 12(b) of the Act:
Each
of
the following classes or series of securities is registered on The New York
Stock Exchange.
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Title
of each class
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Registrant
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Common
Stock, without par value
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SCANA
Corporation
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5%
Cumulative Preferred Stock par value $50 per share
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South
Carolina Electric & Gas
Company
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Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
SCANA
Corporation x
South
Carolina Electric & Gas Company ¨
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act.
SCANA
Corporation ¨
South
Carolina Electric & Gas Company ¨
Indicate
by check mark whether the registrants: (1) have 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 (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past
90 days. 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 definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
SCANA
Corporation ¨
South
Carolina Electric & Gas Company x
Indicate
by check mark whether the registrant is a large accelerated filer, accelerated
filer, or non-accelerated filer (as defined in Exchange Act Rule 12b-2).
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SCANA
Corporation
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Large
accelerated filer x
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Accelerated
filer ¨
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Non-accelerated
filer ¨
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South
Carolina Electric & Gas Company
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Large
accelerated filer ¨
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Accelerated
filer ¨
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Non-accelerated
filer x
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Indicate
by check mark whether the registrant is a shell company (as defined in Exchange
Act Rule 12b-2).
SCANA
Corporation Yes ¨
Nox
South
Carolina Electric & Gas Company Yes ¨
No x
The
aggregate market value of voting stock held by non-affiliates of SCANA
Corporation was $4.5 billion at June 30, 2006 based on the closing price of
$38.58 per share. South Carolina Electric & Gas Company is a wholly owned
subsidiary of SCANA Corporation and has no voting stock other than its common
stock. A description of registrants' common stock follows:
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Registrant
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Description
of Common Stock
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Shares
Outstanding
at
February 20, 2007
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SCANA
Corporation
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Without
Par Value
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116,664,933
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South
Carolina Electric & Gas Company
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$4.50
Par Value
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40,296,147(a)
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(a)
Held
beneficially and of record by SCANA Corporation.
Documents
incorporated by reference: Specified sections of SCANA Corporation's 2006 Proxy
Statement, in connection with its 2007 Annual Meeting of Shareholders, are
incorporated by reference in Part III hereof.
This
combined Form 10-K is separately filed by SCANA Corporation and South
Carolina Electric & Gas Company. Information contained herein relating
to any individual company is filed by such company on its own behalf. Each
company makes no representation as to information relating to the other
company.
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Page
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DEFINITIONS
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4
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PART
I
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Item
1.
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5
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Item
1A.
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14
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Item
1B.
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17
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Item
2.
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18
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Item
3.
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20
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Item
4.
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22
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23
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PART
II
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Item
5.
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24
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Item
6.
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25
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Management's
Discussion and Analysis of Financial Condition and Results of
Operations
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Quantitative
and Qualitative Disclosures About Market Risk
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Financial
Statements and Supplementary Data
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26
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81
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
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127
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Controls
and Procedures
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127
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Other
Information
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129
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PART
III
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Directors
and Executive Officers of the Registrant
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130
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Executive
Compensation
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134
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
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160
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Certain
Relationships and Related Transactions
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161
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Principal
Accountant Fees and Services
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161
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PART
IV
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Exhibits
and Financial Statement Schedules
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162
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164
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166
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The
following abbreviations used in the text have the meanings set forth below
unless the context requires otherwise:
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TERM
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MEANING
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AFC
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Allowance
for Funds Used During Construction
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CAA
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Clean
Air Act, as amended
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CGTC
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Carolina
Gas Transmission Corporation
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DHEC
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South
Carolina Department of Health and Environmental Control
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DOE
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United
States Department of Energy
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DOJ
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United
States Department of Justice
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Dominion
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Dominion
Transmission, Inc.
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DT
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Dekatherm
(one million BTUs)
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Energy
Marketing
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The
divisions of SEMI, excluding SCANA Energy
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EPA
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United
States Environmental Protection Agency
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FERC
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United
States Federal Energy Regulatory Commission
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Fuel
Company
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South
Carolina Fuel Company, Inc.
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GENCO
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South
Carolina Generating Company, Inc.
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GPSC
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Georgia
Public Service Commission
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KW
or KWh
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Kilowatt
or Kilowatt-hour
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LLC
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Limited
Liability Company
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LNG
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Liquefied
Natural Gas
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MCF
or MMCF
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Thousand
Cubic Feet or Million Cubic Feet
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MGP
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Manufactured
Gas Plant
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MMBTU
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Million
British Thermal Units
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MW
or MWh
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Megawatt
or Megawatt-hour
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NCUC
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North
Carolina Utilities Commission
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NMST
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Negotiated
Market Sales Tariff
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NRC
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United
States Nuclear Regulatory Commission
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NSR
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New
Source Review
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NYMEX
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New
York Mercantile Exchange
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PRP
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Potentially
Responsible Party
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PSNC
Energy
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Public
Service Company of North Carolina, Incorporated
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Santee
Cooper
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South
Carolina Public Service Authority
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SCANA
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SCANA
Corporation, the parent company
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SCANA
Energy
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A
division of SEMI which markets natural gas in Georgia
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SCE&G
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South
Carolina Electric & Gas Company
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SCG
Pipeline
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SCG
Pipeline, Inc.
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SCI
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SCANA
Communications, Inc.
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SCPC
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South
Carolina Pipeline Corporation
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SCPSC
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The
Public Service Commission of South Carolina
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SEC
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United
States Securities and Exchange Commission
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SEMI
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SCANA
Energy Marketing, Inc.
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SFAS
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Statement
of Financial Accounting Standards
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Southern
Natural
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Southern
Natural Gas Company
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Summer
Station
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V.
C. Summer Nuclear Station
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Transco
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Transcontinental
Gas Pipeline Corporation
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Williams
Station
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A.M.
Williams Generating Station, owned by GENCO
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WNA
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Weather
Normalization Adjustment
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PART
I
ITEM
1. BUSINESS
CORPORATE
STRUCTURE
SCANA
Corporation (SCANA),
a
holding company, owns the following significant direct, wholly-owned
subsidiaries.
South
Carolina Electric & Gas Company
(SCE&G)
generates and sells electricity to retail and wholesale customers and purchases,
sells and transports natural gas to retail customers.
South
Carolina Generating Company, Inc. (GENCO)
owns and
operates Williams Station and sells electricity solely to
SCE&G.
South
Carolina Fuel Company, Inc. (Fuel
Company)
acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel
and emission allowances.
Public
Service Company of North Carolina, Incorporated (PSNC Energy)
purchases, sells and transports natural gas to retail customers.
Carolina
Gas Transmission Corporation (CGTC)
transports natural gas in southeastern Georgia and South Carolina. CGTC was
formerly known as South Carolina Pipeline Corporation (SCPC), which merged
with
SCG Pipeline, Inc. (SCG Pipeline) effective November 1, 2006.
SCANA
Communications, Inc. (SCI)
provides
fiber optic communications, ethernet services and data center facilities and
builds, manages and leases communications towers in South Carolina, North
Carolina and Georgia.
SCANA
Energy Marketing, Inc.
(SEMI)
markets
natural gas, primarily in the Southeast, and provides energy-related risk
management services. Through its SCANA Energy division, SEMI markets natural
gas
in Georgia's retail natural gas market.
ServiceCare,
Inc.
provides
service contracts on home appliances and heating and air conditioning
units.
Primesouth,
Inc.
provides
management and maintenance services for power plants and a non-affiliated
synthetic fuel production facility.
SCANA
Services, Inc.
provides
administrative, management and other services to the subsidiaries and business
units within SCANA.
SCANA
is
incorporated in South Carolina as is each of its direct, wholly-owned
subsidiaries. In addition to the subsidiaries above, SCANA owns two other
energy-related companies that are insignificant and one additional company
that
is in liquidation.
CAUTIONARY
STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Statements
included in this Annual Report on Form 10-K which are not statements of
historical fact are intended to be, and are hereby identified as,
"forward-looking statements" for purposes of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of
1934, as amended. Forward-looking statements include, but are not limited to,
statements concerning key earnings drivers, customer growth, environmental
regulations and expenditures, leverage ratio, projections for pension fund
contributions, financing activities, access to sources of capital, impacts
of
the adoption of new accounting rules, estimated construction and other
expenditures and factors affecting the availability of synthetic fuel tax
credits. In some cases, forward-looking statements can be identified by
terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,”
“anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or
“continue” or the negative of these terms or other similar terminology. Readers
are cautioned that any such forward-looking statements are not guarantees of
future performance and involve a number of risks and uncertainties, and that
actual results could differ materially from those indicated by such
forward-looking statements. Important factors that could cause actual results
to
differ materially from those indicated by such forward-looking statements
include, but are not limited to, the following:
(1) the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment;
(2) regulatory
actions, particularly changes in rate regulation and environmental regulations;
(3) current
and future litigation;
(4) changes
in the economy, especially in areas served by subsidiaries of SCANA;
(5) the
impact of competition from other energy suppliers, including competition from
alternate fuels in industrial
interruptible markets;
(6) growth
opportunities for SCANA's regulated and diversified subsidiaries;
(7) the
results of financing efforts;
(8) changes
in SCANA’s or its subsidiaries’ accounting rules and accounting policies;
(9) weather
conditions, especially in areas served by SCANA's subsidiaries;
(10)
payment by counterparties as and when due;
(11)
the
availability of fuels such as coal, natural gas and enriched uranium used to
produce electricity; the availability
of purchased power and natural gas for distribution; the level and
volatility of future market prices for such fuels
and purchased power; and the ability to recover the costs for such fuels and
purchased power;
(12) performance
of the Company's pension plan assets;
(13) inflation;
(14) compliance
with regulations; and
(15) the
other risks and uncertainties described from time to time in the periodic
reports filed by SCANA or its subsidiaries
with the United States Securities and Exchange Commission (SEC), including
those
risks described in Item 1A, Risk
Factors.
SCANA
and SCE&G disclaim any obligation to update any forward-looking
statements.
ORGANIZATION
SCANA
is
a South Carolina corporation created in 1984 as a holding company. SCANA holds,
directly or indirectly, all of the capital stock of each of its subsidiaries
except for the preferred stock of SCE&G. SCANA and its subsidiaries had
full-time, permanent employees as of February 20, 2007 and 2006 of 5,683
and 5,628, respectively. SCE&G is an operating public utility incorporated
in 1924 as a South Carolina corporation. SCE&G had full-time, permanent
employees as of February 20, 2007 and 2006 of 2,908 and 2,865,
respectively.
INVESTOR
INFORMATION
SCANA's
and SCE&G's annual reports on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K and amendments to those reports
filed with or furnished to the SEC are available free of charge through SCANA's
internet website at www.scana.com
as soon
as reasonably practicable after these reports are filed or furnished.
Information on SCANA's website is not part of this or any other report filed
with or furnished to the SEC.
SEGMENTS
OF BUSINESS
SCANA
does not directly own or operate any physical properties. SCANA, through its
subsidiaries, is engaged in the functionally distinct operations described
below. SCANA also has an investment in one limited liability company (LLC)
which
owns and operates a cogeneration facility in Charleston, South Carolina.
For
information with respect to major segments of business, see Management's
Discussion and Analysis of Financial Condition and Results of Operations for
SCANA and SCE&G and the consolidated financial statements for SCANA and
SCE&G (Note 11). All such information is incorporated herein by
reference.
Regulated
Utilities
SCE&G
generates, transports (transmission and distribution) and sells electricity
to
623,400 customers and buys, sells and transports (retail) natural gas to 297,000
customers (each as of December 31, 2006). SCE&G's business experiences
seasonal fluctuations, with generally higher sales of electricity during the
summer and winter months because of air conditioning and heating requirements,
and generally higher sales of natural gas during the winter months due to
heating requirements. SCE&G's electric service territory extends into 24
counties covering nearly 17,000 square miles in the central, southern and
southwestern portions of South Carolina. The service area for natural gas
encompasses all or part of 35 counties in South Carolina and covers more than
23,000 square miles. More than 3.0 million persons live in the counties where
SCE&G conducts its business. Resale customers include municipalities,
electric cooperatives, other investor-owned utilities, registered marketers
and
federal and state electric agencies. Predominant industries served by SCE&G
include synthetic fibers, chemicals, fiberglass, paper and wood, metal
fabrication, stone, clay and sand mining and processing and textile
manufacturing.
GENCO
owns Williams Station and sells electricity solely to SCE&G.
Fuel
Company acquires, owns and provides financing for SCE&G's nuclear fuel,
fossil fuel and emission allowances.
PSNC
Energy buys, sells and transports natural gas to 441,500 residential, commercial
and industrial customers (as of December 31, 2006). PSNC Energy serves 28
franchised counties covering 12,000 square miles in North Carolina. The
industrial customers of PSNC Energy include manufacturers or processors of
ceramics and clay products, glass, automotive products, pharmaceuticals,
plastics, metals and a variety of food and tobacco products.
Effective
November 1, 2006, SCG Pipeline merged into SCPC and the merged company changed
its name to CGTC. CGTC operates as an open access, transportation-only
interstate pipeline company regulated by the Federal Energy Regulatory
Commission (FERC). CGTC operates in southeastern Georgia and in South Carolina
and has interconnections with Southern Natural Gas Company (Southern
Natural)
at Port
Wentworth, Georgia and with Southern LNG, Inc. at Elba Island, near Savannah,
Georgia. CGTC also has interconnections with Southern Natural in Aiken County,
South Carolina, and with Transcontinental Gas Pipeline Corporation (Transco)
in
Cherokee and Spartanburg counties, South Carolina. CGTC’s customers include
SCE&G (which uses natural gas for electricity generation and for gas
distribution to retail customers), SEMI (which markets natural gas to industrial
and sale for resale customers, primarily in the Southeast), other natural gas
utilities, municipalities and county gas authorities, and industrial customers
primarily engaged in the manufacturing or processing of ceramics, paper, metal,
food and textiles.
Prior
to
the November 1, 2006 merger, SCPC was an intrastate natural gas pipeline engaged
in the purchase, transmission and sale of natural gas on a wholesale basis
to
distribution companies (including SCE&G) and industrial customers throughout
most of South Carolina. SCG Pipeline had provided interstate transportation
services for natural gas to southeastern Georgia and South Carolina.
Nonregulated
Businesses
SEMI
markets natural gas primarily in the southeast and provides energy-related
risk
management services. SCANA Energy, a division of SEMI, markets natural gas
to
over 475,000 customers (as of December 31, 2006) in Georgia's natural gas
market. The Georgia Public Service Commission (GPSC) has contracted with SCANA
Energy to serve as the state’s regulated provider until August 31, 2007.
Currently, SCANA Energy serves over 90,000 customers (as of December 31, 2006)
under this regulated provider contract, which includes low-income and high
credit risk customers. SCANA Energy's total customer base represents over a
30%
share of the approximately 1.5 million customers in Georgia's deregulated
natural gas market. SCANA Energy remains the second largest natural gas marketer
in the state.
SCI
owns
and operates a 500-mile fiber optic telecommunications network and ethernet
network and data center facilities in South Carolina. Through a joint venture,
SCI has an interest in an additional 1,742 miles of fiber in South Carolina,
North Carolina and Georgia. SCI also provides tower site construction,
management and rental services in South Carolina and North Carolina.
The
preceding Corporate Structure section describes other significant businesses
owned by SCANA.
COMPETITION
For
a
discussion of the impact of competition, see the Overview section of
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G.
CAPITAL
REQUIREMENTS
SCANA’s
regulated subsidiaries require cash to fund operations, construction programs
and dividend payments to SCANA. To replace existing plant investment and to
expand to meet future demand for electricity and gas, SCANA’s regulated
subsidiaries must attract the necessary financial capital on reasonable terms.
Regulated subsidiaries recover the costs of providing services through rates
charged to customers. Rates for regulated services are generally based on
historical costs. As customer growth and inflation occur and these subsidiaries
continue their construction programs, rate increases will be sought. The future
financial position and results of operations of the regulated subsidiaries
will
be affected by their ability to obtain adequate and timely rate and other
regulatory relief, when requested.
For
a
discussion of various rate matters and their impact on capital requirements,
see
the Regulatory Matters section of Management's Discussion and Analysis of
Financial Condition and Results of Operations for SCANA and SCE&G and
Note 2 to the consolidated financial statements for SCANA and
SCE&G.
During
the three-year period 2007-2009, SCANA and SCE&G expect to meet capital
requirements through internally generated funds and short-term and long-term
borrowings. SCANA and SCE&G expect that they have or can obtain adequate
sources of financing to meet their projected cash requirements for the next
12 months and for the foreseeable future.
For
a
discussion of cash requirements for construction and nuclear fuel expenditures,
see the Liquidity and Capital Resources section of Management's Discussion
and
Analysis of Financial Condition and Results of Operations for SCANA and
SCE&G.
CAPITAL
PROJECTS
For
a
discussion of contractual cash obligations, financing limits, financing
transactions and other related information, see the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial Condition
and Results of Operations for SCANA and SCE&G.
SCANA's
ratios of earnings to fixed charges were 2.94, 2.19, 2.65, 2.82 and 0.53 for
the
years ended December 31, 2006, 2005, 2004, 2003 and 2002, respectively. To
achieve a ratio of 1.0 for the year ended December 31, 2002, SCANA would
have needed to earn an additional $108.6 million in income before income
taxes. SCANA's ratio for 2002 was negatively impacted by the impairment charge
related to the acquisition adjustment associated with SCANA’s purchase in 2000
of PSNC Energy and the impairments of SCANA's investments in certain
telecommunications securities. SCE&G’s ratios of earnings to fixed charges
were 3.08, 2.10, 3.15, 3.01 and 3.13 for the same periods. SCANA’s and
SCE&G’s ratios for 2005 were negatively impacted by the large amounts of
accelerated depreciation discussed at Results of Operations - Income Taxes
-
Recognition
of Synthetic Fuel Tax Credits
in their
respective Management’s Discussion and Analysis of Financial Condition and
Results of Operations sections, and because the calculation necessarily excludes
the related and fully offsetting tax benefits recorded in that
year.
ELECTRIC
OPERATIONS
Electric
Sales
SCE&G's
sales of electricity by class as a percent of electric revenues for 2005 and
2006 were as follows:
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CLASSIFICATION
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2005
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2006
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Residential
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39
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%
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40
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%
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Commercial
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29
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%
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31
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%
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Industrial
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17
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%
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17
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%
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Sales
for resale
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4
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%
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4
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%
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Other
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2
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%
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2
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%
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Total
Territorial
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91
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%
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94
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%
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Negotiated
Market Sales Tariff (NMST)
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9
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%
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6
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%
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Total
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|
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100
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%
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100
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%
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Sales
for
resale include sales to five municipalities. Sales under the NMST during 2006
include sales to 25 investor-owned utilities or registered marketers, three
electric cooperatives and three federal/state electric agencies. During 2005
sales under the NMST included sales to 49 investor-owned utilities or registered
marketers, seven electric cooperatives, two municipalities and three
federal/state electric agencies.
During
2006 SCE&G recorded a net increase of 13,400 customers (growth rate of
2.2%), increasing its total electric customers to 623,400 at year end. During
2006, SCE&G’s peak summer demand did not exceed the all-time peak demand of
4,820 megawatts (MW) set on July 27, 2005.
For
the
three-year period 2007-2009, SCE&G projects total territorial kilowatt hour
(KWh) sales of electricity to increase 2.2% annually (assuming normal weather),
total electric customer base to increase 2.3% annually and territorial peak
load
(summer, in MW) to increase 1.9% annually. SCE&G's goal is to maintain a
reserve margin of between 12% and 18%. As of December 31, 2006 the reserve
margin was approximately 12.6%.
Electric
Interconnections
SCE&G
purchases all of the electric generation of GENCO's Williams Station under
a
Unit Power Sales Agreement which has been approved by FERC. Williams Station
has
a net generating capacity (summer rating) of 615 MW.
SCE&G's
transmission system forms part of an interconnected grid extending over a large
part of the southern and eastern portions of the nation. SCE&G, Dominion
Virginia Power, Duke Power Carolinas, Progress Energy Carolinas, APGI (Yadkin
Division) and the South Carolina Public Service Authority (Santee Cooper) are
members of the Virginia-Carolinas Reliability Group, one of several geographic
divisions within the Southeastern Electric Reliability Council (SERC). SERC
is
the Regional Reliability Organization (RRO) responsible for promoting,
coordinating and ensuring the reliability and adequacy of the bulk power supply
systems in the area served by the member systems. SCE&G also interconnects
with Georgia Power Company, Oglethorpe Power Corporation and the Southeastern
Power Administration's Clarks Hill Project. For a discussion of the impact
certain legislative and regulatory initiatives may have on SCE&G's
transmission system, see Electric Operations within the Overview section of
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G.
Fuel
Costs and Fuel Supply
The
average cost of various fuels and the weighted average cost of all fuels
(including oil) for the years 2004-2006 follow:
|
|
|
Cost
of Fuel Used
|
|
|||||||
|
|
|
2004
|
2005
|
2006
|
|
|||||
|
Per
million British thermal units (MMBTU):
|
|
|
|
|
|
|
|
|||
|
Nuclear
|
|
$
|
.50
|
|
$
|
.46
|
|
$
|
.43
|
|
|
Coal
|
|
|
1.96
|
|
|
2.38
|
|
|
2.54
|
|
|
Gas
|
|
|
7.54
|
|
|
10.50
|
|
|
8.18
|
|
|
All
Fuels (weighted average)
|
|
|
1.96
|
|
|
2.53
|
|
|
2.57
|
|
|
Per
Ton:
|
|
|
|
|
|
|
|
|
|
|
|
Coal
|
|
$
|
48.54
|
|
$
|
59.07
|
|
$
|
63.13
|
|
|
Per
thousand cubic feet (MCF):
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
7.81
|
|
$
|
10.91
|
|
$
|
8.57
|
|
The
sources and percentages of total megawatt hour (MWh) generation by each category
of fuel for the years 2004-2006 and the estimates for the years 2007-2009
follow:
|
|
|
%
of Total MWh Generated
|
|
||||||||||||||||
|
|
|
Actual
|
Estimated
|
|
|||||||||||||||
|
|
|
2004
|
2005
|
2006
|
2007
|
2008
|
2009
|
|
|||||||||||
|
Coal
|
|
|
68
|
%
|
|
68
|
%
|
|
67
|
%
|
|
61
|
%
|
|
63
|
%
|
|
62
|
%
|
|
Nuclear
|
|
|
21
|
%
|
|
19
|
%
|
|
19
|
%
|
|
19
|
%
|
|
18
|
%
|
|
18
|
%
|
|
Hydro
|
|
|
4
|
%
|
|
5
|
%
|
|
4
|
%
|
|
6
|
%
|
|
5
|
%
|
|
5
|
%
|
|
Natural
Gas & Oil
|
|
|
7
|
%
|
|
8
|
%
|
|
10
|
%
|
|
14
|
%
|
|
14
|
%
|
|
15
|
%
|
|
Total
|
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Six
of
the fossil fuel-fired plants use coal. Unit trains and in some cases trucks
deliver coal to these plants.. On December 31, 2006 SCE&G had
approximately a 63-day supply of coal in inventory.
Coal
is
obtained through long-term supply contracts and spot market purchases. Long-term
contracts exist with eight suppliers located in eastern Kentucky, Tennessee,
West Virginia and southwest Virginia. These contracts provide for approximately
4.5 million tons annually, which is 71% of total expected coal purchases
for 2007. Sulfur restrictions on the contract coal range from 1.0% to 1.5%.
These contracts expire at various times through 2010. Spot market purchases
are
expected to continue when needed or when prices are favorable.
SCANA and
SCE&G believe that SCE&G's operations comply with all existing
regulations relating to the discharge of sulfur dioxide and nitrogen oxides.
See
additional discussion at Environmental Matters in Management's Discussion and
Analysis of Financial Condition and Results of Operations for SCANA and
SCE&G.
SCE&G
has adequate supplies of uranium or enriched uranium product under contract
to
manufacture nuclear fuel for the V. C. Summer Nuclear Station (Summer Station)
through 2009. The following table summarizes contract commitments for the stages
of nuclear fuel assemblies:
|
Commitment
|
Contractor
|
Remaining
Regions(a)
|
Expiration
Date
|
|
Uranium
|
United
States Enrichment Corporation
|
20-21
|
2009
|
|
Enrichment
|
United States Enrichment Corporation
|
20-24
|
2014
|
|
Fabrication
|
Westinghouse
Electric Corporation
|
20-22
|
2011
|
(a)
A
region represents approximately one-third to one-half of the nuclear core in
the
reactor at any one time. Region 19 was
loaded
in
2006.
SCE&G
can store spent nuclear fuel on-site until at least 2018 and expects to expand
its storage capacity to accommodate the spent fuel output for the life of Summer
Station through dry cask storage or other technology as it becomes available.
In
addition, Summer Station has sufficient on-site storage capacity to permit
storage of the entire reactor core in the event that complete unloading should
become desirable or necessary. For information about the contract and related
litigation with the United States Department of Energy (DOE) regarding disposal
of spent fuel, see Nuclear Fuel Disposal within the Environmental Matters
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations for SCANA and SCE&G.
GAS
OPERATIONS
Gas
Sales-Regulated
Sales
of
natural gas by class as a percent of total regulated gas revenues sold or
transported for 2005 and 2006 were as follows:
|
|
|
SCANA
|
SCE&G
|
||||||||||
|
CLASSIFICATION
|
|
2005
|
2006
|
2005
|
2006
|
||||||||
|
Residential
|
|
|
40.6
|
%
|
|
42.6
|
%
|
|
36.6
|
%
|
|
38.4
|
%
|
|
Commercial
|
|
|
25.5
|
%
|
|
25.6
|
%
|
|
32.3
|
%
|
|
30.2
|
%
|
|
Industrial
|
|
|
29.6
|
%
|
|
27.6
|
%
|
|
30.6
|
%
|
|
30.7
|
%
|
|
Sales
for Resale
|
|
|
1.3
|
%
|
|
0.9
|
%
|
|
-
|
|
|
-
|
|
|
Transportation
Gas
|
|
|
3.0
|
%
|
|
3.3
|
%
|
|
0.5
|
%
|
|
0.7
|
%
|
|
Total
|
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
For
the
three-year period 2007-2009, SCANA projects total consolidated sales of
regulated natural gas in dekatherms (DT) to increase 2.2% annually (assuming
normal weather). Annual projected increases in DT sales include residential
of
2.6%, commercial of 1.7% and industrial 2.0%.
SCANA's
total consolidated natural gas customer base is projected to increase 3.6%
annually. During 2006 SCANA recorded a net increase of 21,600 regulated gas
customers (growth rate of 3.0%), increasing its regulated gas customers to
739,000. Of this increase, SCE&G recorded a net increase of 5,500 gas
customers (growth rate of 1.9%), increasing its total gas customers to 297,000
(as of December 31, 2006).
Demand
for gas changes primarily due to the effect of weather and the price
relationship between gas and alternate fuels.
For
most
of 2006, SCPC operated wholly within South Carolina and provided natural gas
and
transportation services for its industrial customers, and supplied natural
gas
to SCE&G and other wholesale purchasers. On November 1, 2006, SCG Pipeline
was merged into SCPC, forming CGTC. CGTC is an interstate transmission pipeline
regulated by FERC and operating in South Carolina and Georgia. See Gas
Transmission within the Overview Section of SCANA's Management Discussion and
Analysis of Financial Condition and Results of Operations.
Gas
Cost,
Supply and Curtailment Plans
South
Carolina
SCG
Pipeline merged into SCPC and the merged company changed its name to CGTC,
effective November 1, 2006. As a result of this merger SCPC's existing customers
were allocated their pro rata share of SCPC's upstream firm interstate pipeline
transportation and storage contracts. In addition, SCPC transferred both of
its
LNG facilities to SCE&G. SCE&G purchases natural gas under contracts
with producers and marketers in both the spot and long-term markets. The gas
is
brought to South Carolina through transportation agreements with Southern
Natural Gas Company (Southern Natural) (expiring in 2010), Transcontinental
Gas
Pipeline Corporation (Transco) (expiring in 2008 and 2017) and CGTC (expiring
2009). The daily volume of gas that SCE&G is entitled to transport under
these contracts on a firm basis is 161,143 DT from Southern Natural, 64,652
DT
from Transco and 296,560 DT from CGTC. Natural gas volumes may be brought to
SCE&G's system as capacity is available for interruptible transportation. In
addition, SCE&G, under contract with SEMI, is entitled to receive a daily
contract demand of 120,000 DTs for use in either electric generation or for
resale to SCE&G’s customers.
The
daily
volume of gas that SEMI is entitled to transport under its service agreement
with CGTC (expiring in 2023) on a firm basis is 198,083 DT.
SCE&G
purchased natural gas at an average cost of $9.82 per MCF during 2006 and $10.29
per MCF during 2005.
SCE&G
was allocated 5,406 MMCF of natural gas storage space on Southern Natural and
Transco. Approximately 4,660 MMCF of gas were in storage on December 31,
2006. To meet the requirements of its high priority natural gas customers during
periods of maximum demand, SCE&G supplements its supplies of natural gas
with two LNG liquefaction and storage facilities which it acquired from SCPC.
The LNG plants are capable of storing the liquefied equivalent of 1,880 MMCF
of
natural gas. Approximately 1,633 MMCF (liquefied equivalent) of gas were in
storage at December 31, 2006. In the fourth quarter of 2006, SCE&G
purchased these LNG plants and related inventory from SCPC at net book value
and
SCPC also assigned its rights and obligations under the contracts for storage
space to SCE&G and SCE&G purchased the related inventory at book
value.
North
Carolina
PSNC
Energy purchases natural gas under contracts with producers and marketers on
a
short-term basis at current price indices and on a long-term basis for
reliability assurance at index prices plus a reservation charge. Transco and
Dominion Transmission, Inc. (Dominion) deliver the gas to North Carolina through
transportation agreements with expiration dates ranging through 2016. PSNC
Energy may transport daily volumes of gas under these contracts on a firm basis
of 259,894 DT from Transco and 30,331 DT from Dominion. In addition, PSNC Energy
is entitled to firm transportation service on the Patriot Extension Project,
a
project of East Tennessee Natural Gas Company, and firm storage service on
the
Saltville Storage Project, an affiliate of East Tennessee Natural Gas Company,
that provide an aggregate daily demand of 30,000 DT.
PSNC
Energy purchased natural gas at an average cost of $9.47 per DT during 2006
compared to $10.63 per DT during 2005.
To
meet
the requirements of its high priority natural gas customers during periods
of
maximum demand, PSNC Energy supplements its supplies of natural gas with
underground natural gas storage services and LNG peaking services. Underground
natural gas storage service agreements with Dominion, Columbia Gas Transmission,
Transco and East Tennessee Natural Gas Company provide for storage capacity
of
approximately 12,700 MMCF. Approximately 11,200 MMCF of gas were in storage
at
December 31, 2006. In addition, PSNC Energy's own LNG facility can store
the liquefied equivalent of 1,000 MMCF of natural gas with regasification
capability of approximately 100 MMCF per day. Approximately 600 MMCF (liquefied
equivalent) of gas were in storage at December 31, 2006. LNG storage
service agreements with Transco, Cove Point LNG and Pine Needle LNG provide
for
1,300 MMCF (liquefied equivalent) of storage space. Approximately 1,200 MMCF
(liquefied equivalent) were in storage at December 31, 2006.
SCANA
and
SCE&G believe that supplies under long-term contracts and supplies available
for spot market purchase are adequate to meet existing customer demands and
to
accommodate growth.
Gas
Marketing-Nonregulated
SEMI
markets natural gas and provides energy-related risk management services
primarily in the Southeast. In addition, SCANA Energy, a division of SEMI,
markets natural gas to over 475,000 customers (as of December 31, 2006) in
Georgia's natural gas market. SCANA Energy's total customer base represents
over
a 30% share of the approximately 1.5 million customers in Georgia's
deregulated natural gas market. SCANA Energy remains the second largest natural
gas marketer in the state.
Risk
Management
SCANA
and
SCE&G established policies and procedures and risk limits to control the
level of market, credit, liquidity and operational and administrative risks
assumed by them. The Board of Directors of each company has delegated to a
Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and to oversee and review the
risk management process and infrastructure. The Risk Management Committee,
which
is comprised of certain officers, including a Risk Management Officer and senior
officers, apprises the Board of Directors of each company with regard to the
management of risk and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for
transactions.
REGULATION
SCANA,
together with its subsidiaries, is subject to the jurisdiction of the SEC and
FERC as to the issuance of certain securities, acquisitions and other matters.
State public service commissions or FERC regulate certain subsidiaries of SCANA
as to the following matters.
SCE&G
is subject to the jurisdiction of the SCPSC as to retail electric and gas rates,
service, accounting, issuance of securities (other than short-term borrowings)
and other matters. SCE&G is subject to the jurisdiction of FERC as to
issuance of short-term borrowings and other matters.
GENCO
is
subject to the jurisdiction of the SCPSC as to issuance of securities (other
than short-term borrowings) and is subject to the jurisdiction of FERC as to
issuance of short-term borrowings, accounting and other matters.
PSNC
Energy is subject to the jurisdiction of the North Carolina Utilities Commission
(NCUC) as to gas rates, service, issuance of securities (other than notes with
a
maturity of two years or less or renewals of notes with a maturity of six years
or less), accounting and other matters.
CGTC
is
subject to the jurisdiction of FERC as to transportation rates, service,
accounting and other matters.
SCANA
Energy is regulated by the GPSC through its certification as a natural gas
marketer in Georgia and specifically is subject to the jurisdiction of the
GPSC
as to gas rates for certain of its customers classified as low-income or high
credit risk and as to certain other marketing activities.
SCE&G
and GENCO are subject to regulation under the Federal Power Act, administered
by
FERC and DOE, in the transmission of electric energy in interstate commerce
and
in the sale of electric energy at wholesale for resale, as well as with respect
to licensed hydroelectric projects and certain other matters, including
accounting. See the Regulatory Matters section of Management's Discussion and
Analysis of Financial Condition and Results of Operations for SCANA and
SCE&G.
SCE&G
and GENCO have obtained FERC authority to issue short-term indebtedness
(pursuant to Section 204 of the Federal Power Act). SCE&G may issue up to
$700 million of unsecured promissory notes or commercial paper with maturity
dates of one year or less, and GENCO may issue up to $100 million of such
short-term indebtedness. FERC’s approval expires February 7, 2008.
SCE&G
holds licenses under the Federal Water Power Act or the Federal Power Act for
each of its hydroelectric projects. The licenses expire as follows:
|
Project
|
License
Expiration
|
Project
|
License
Expiration
|
|
Saluda
(Lake Murray)
|
2010
|
Stevens
Creek
|
2025
|
|
Fairfield
Pumped Storage
|
2020
|
Neal
Shoals
|
2036
|
|
Parr
Shoals
|
2020
|
SCE&G
expects to apply to FERC for relicensing of the Saluda project in 2008.
At
the
termination of a license under the Federal Power Act, FERC may extend or issue
a
new license to the previous licensee, FERC may issue a license to another
applicant or the federal government may take over the related project. If the
federal government takes over a project or if FERC issues a license to another
applicant, the federal government or the new licensee, as the case may be,
must
pay the previous licensee an amount equal to its net investment in the project,
not to exceed fair value, plus severance damages.
For
a
discussion of legislative and regulatory initiatives being implemented that
will
affect SCE&G's transmission system, see Electric Operations within the
Overview section of Management's Discussion and Analysis of Financial Condition
and Results of Operations for SCANA and SCE&G.
SCE&G
is subject to regulation by the United States Nuclear Regulatory Commission
(NRC) with respect to the ownership, operation and decommissioning of Summer
Station. The NRC's jurisdiction encompasses broad supervisory and regulatory
powers over the construction and operation of nuclear reactors, including
matters of health and safety, antitrust considerations and environmental impact.
In addition, the Federal Emergency Management Agency reviews, in conjunction
with the NRC, certain aspects of emergency planning relating to the operation
of
nuclear plants.
RATE
MATTERS
For
a
discussion of the impact of various rate matters, see the Regulatory Matters
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations for SCANA and SCE&G, and Note 2 to the
consolidated financial statements for SCANA and SCE&G.
SCE&G's
and PSNC Energy's gas rate schedules for their residential and small commercial
and small industrial customers include a weather normalization adjustment (WNA).
SCE&G's and PSNC Energy's WNA were approved by the SCPSC and NCUC,
respectively, and are in effect for bills rendered during the period
November 1 through April 30 of each year. In each case the WNA
increases tariff rates if weather is warmer than normal and decreases rates
if
weather is colder than normal. The WNA does not change the seasonality of gas
revenues, but reduces fluctuations in revenues and earnings caused by abnormal
weather.
Fuel
Cost
Recovery Procedures
The
SCPSC’s fuel cost recovery procedure determines the fuel component in
SCE&G's retail electric base rates annually based on projected fuel costs
for the ensuing 12-month period, adjusted for any overcollection or
undercollection from the preceding 12-month period. SCE&G may request a
formal proceeding at any time should circumstances dictate such a review. As
part of the annual review of fuel costs, the SCPSC approved SCE&G’s request
to increase the cost of fuel component from 2.256 cents per KWh to 2.516 cents
per KWh effective the first billing cycle in May 2006.
SCE&G's
gas rate schedules and contracts include mechanisms that allow it to recover
from its customers changes in the actual cost of gas. SCE&G's firm gas rates
allow for the recovery of the cost of gas, based on projections, as established
by the SCPSC. Beginning in December 2006, SCE&G is authorized to adjust its
cost of gas on a monthly, rather than annual, basis.
In
addition to WNA, PSNC Energy’s Rider D rate mechanism serves to reduce
fluctuations in PSNC Energy’s earnings. The Rider D mechanism allows PSNC Energy
to recover, in any manner authorized by the NCUC, losses on negotiated gas
and
transportation sales. The Rider D rate mechanism also allows PSNC Energy to
recover from customers all prudently incurred gas costs. Effective December
1,
2005 PSNC Energy also recovers certain uncollectible expenses related to gas
cost.
PSNC
Energy's rates are established using a benchmark cost of gas approved by the
NCUC, which may be modified periodically to reflect changes in the market price
of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary
to
track these changes and accounts for any over- or under-collections of the
delivered cost of gas in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC Energy's gas purchasing practices
annually.
ENVIRONMENTAL
MATTERS
Federal
and state authorities have imposed environmental regulations and standards
relating primarily to air emissions, wastewater discharges and solid, toxic
and
hazardous waste management. Developments in these areas may require that
equipment and facilities be modified, supplemented or replaced. The ultimate
effect of these regulations and standards upon existing and proposed operations
cannot be predicted. For a more complete discussion of how these regulations
and
standards impact SCANA and SCE&G, see the Environmental Matters section of
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G and the consolidated financial statements for
SCANA and SCE&G (Note 10B).
OTHER
MATTERS
For
a
discussion of SCE&G's insurance coverage for Summer Station, see
Note 10A to the consolidated financial statements for SCANA and
SCE&G.
ITEM
1A. RISK FACTORS
The
risk factors that follow relate in each case to SCANA Corporation and its
subsidiaries (the Company), and where indicated the risk factors also relate
to
South Carolina Electric & Gas Company and its consolidated affiliates
(SCE&G).
Commodity
price changes may affect the operating costs and competitive positions of the
Company's and SCE&G's energy businesses, thereby adversely impacting results
of operations, cash flows and financial condition.
Our
energy businesses are sensitive to changes in coal, gas, oil and other commodity
prices and availability. Any changes could affect the prices these businesses
charge, their operating costs and the competitive position of their products
and
services. SCE&G is able to recover the cost of fuel used in electric
generation through retail customers' bills, but increases in fuel costs affect
electric prices and, therefore, the competitive position of electricity against
other energy sources. In the case of regulated natural gas operations, costs
for
purchased gas and pipeline capacity are recovered through retail customers'
bills, but increases in gas costs affect total retail prices and, therefore,
the
competitive position of gas relative to electricity and other forms of energy.
Increases in gas costs may also result in lower usage by customers unable to
switch to alternate fuels.
The
Company and SCE&G do not fully hedge against price changes in commodities.
This could result in increased costs, thereby resulting in lower margins and
adversely affecting results of operations, cash flows and financial
condition.
The
Company and SCE&G attempt to manage commodity price exposure by establishing
risk limits and entering into contracts to offset some of our positions (i.e.,
to hedge our exposure to demand, market effects of weather and other changes
in
commodity prices). We do not hedge the entire exposure of our operations from
commodity price volatility. To the extent we do not hedge against commodity
price volatility or our hedges are not effective, results of operations, cash
flows and financial condition may be diminished.
Changing
and complex laws and regulations to which the Company and SCE&G are subject
could adversely affect revenues or increase costs or curtail activities, thereby
adversely impacting results of operations, cash flows and financial
condition.
The
Company and SCE&G must comply with extensive federal, state and local laws
and regulations. Such regulation widely affects the operation of our business.
The effects encompass, among many other aspects of our business, the licensing
and siting of facilities, safety, reliability of our transmission system,
security of key assets, information privacy, the issuance of securities,
financial reporting, interaction among affiliates, and the payment of dividends.
Changes to these regulations are ongoing, and we cannot predict the future
course of changes in this regulatory environment or the ultimate effect that
this changing regulatory environment will have on the Company’s or SCE&G’s
business.
The
Company and SCE&G are subject to extensive rate regulation which could
adversely affect operations. In particular, SCE&G's electric operations in
South Carolina and the Company's gas operations in South Carolina (including
SCE&G) and North Carolina are regulated by state utilities commissions. Our
gas marketing operations in Georgia are also subject to state regulatory
oversight. There can be no assurance that Georgia’s gas delivery regulatory
framework will remain unchanged as dynamic market conditions evolve. Although
we
believe we have constructive relationships with our regulators, our ability
to
obtain rate increases that will allow us to maintain reasonable rates of return
is dependent upon regulatory discretion, and there can be no assurance that
we
will be able to implement rate increases when sought.
In
addition, compliance with extensive federal, state and local environmental
laws
and regulations requires us to commit significant capital toward environmental
monitoring, installation of pollution control equipment, emission fees and
permits at our facilities. These expenditures have been significant in the
past
and are expected to increase in the future. Changes in compliance requirements
or a more burdensome interpretation by governmental authorities of existing
requirements may impose additional costs on us or require us to curtail some
of
our activities. Costs of compliance with environmental regulations could harm
our industry, our business and our results of operations and financial position,
especially if emission or discharge limits are reduced, more extensive
permitting requirements are imposed or additional regulatory requirements are
imposed.
The
Company and SCE&G are vulnerable to interest rate increases which would
increase our borrowing costs, and may not have access to capital at favorable
rates, if at all, both of which may adversely affect results of operations,
cash
flows and financial condition.
Changes
in interest rates can affect the cost of borrowing on variable rate debt
outstanding, on refinancing of debt maturities and on incremental borrowing
to
fund new investments. The Company's and SCE&G’s business plans reflect the
expectation that we will have access to the capital markets on satisfactory
terms to fund commitments. Moreover, the ability to maintain short-term
liquidity by utilizing commercial paper programs is dependent upon maintaining
investment grade debt ratings. The liquidity of the Company and SCE&G would
be adversely affected by unfavorable changes in the commercial paper market
or
if bank credit facilities became unavailable at acceptable rates.
SCANA
may not be able to maintain its leverage ratio at a level considered appropriate
by debt rating agencies. This could result in downgrades of SCANA's debt
ratings, thereby increasing its borrowing costs and adversely affecting its
results of operations, cash flows and financial
condition.
SCANA's
leverage ratio of debt to capital increased significantly following its
acquisition in 2000 of PSNC Energy, and was approximately 55% at
December 31, 2006. SCANA has publicly announced its desire to maintain this
leverage ratio at 54% to 55%, but SCANA's ability to do so depends on a number
of factors. If SCANA is not able to maintain its leverage ratio, SCANA's debt
ratings may be affected, it may be required to pay higher interest rates on
its
long- and short-term indebtedness, and its access to the capital markets may
be
limited.
A
downgrade in the credit rating of SCANA or any of SCANA’s subsidiaries,
including SCE&G, could negatively affect their ability to access capital and
to operate their businesses, thereby adversely affecting results of operations,
cash flows and financial condition.
Standard &
Poor's Ratings Services (S&P), Moody's Investors Service (Moody's) and Fitch
Ratings (Fitch) rate SCANA's long-term senior unsecured debt at BBB+, A3 and
A-,
respectively, each with a stable outlook. S&P, Moody's and Fitch rate
SCE&G's long-term senior secured debt at A-, A1 and A+, respectively, with a
stable outlook. S&P, Moody’s and Fitch rate PSNC Energy's long-term senior
unsecured debt at A-, A2 and A, respectively, with a stable outlook. If S&P,
Moody's or Fitch were to downgrade any of these long-term ratings, particularly
to below investment grade, borrowing costs would increase, which would diminish
financial results, and the potential pool of investors and funding sources
could
decrease. S&P, Moody's and Fitch rate the short-term debt of SCE&G and
PSNC Energy at A-2, P-1 and F-1, respectively. If these short-term ratings
were
to decline, it could significantly limit access to the commercial paper market
and other sources of liquidity.
Operating
results may be adversely affected by abnormal
weather.
The
Company and SCE&G have historically sold less power, delivered less gas and
received lower prices for natural gas in deregulated markets, and consequently
earned less income, when weather conditions are milder than normal. Mild weather
in the future could diminish the revenues and results of operations and harm
the
financial condition of the Company and SCE&G. In addition, severe weather
can be destructive, causing outages and property damage, adversely affecting
operating expenses and revenues.
Potential
competitive changes may adversely affect our gas and electricity businesses
due
to the loss of customers, reductions in revenues, or write-down of stranded
assets.
The
utility industry has been undergoing dramatic structural change for several
years, resulting in increasing competitive pressures on electric and natural
gas
utility companies. Competition in wholesale power sales has been introduced
on a
national level. Some states have also mandated or encouraged competition at
the
retail level. Increased competition may create greater risks to the stability
of
utility earnings generally and may in the future reduce earnings from retail
electric and natural gas sales. In a deregulated environment, formerly regulated
utility companies that are not responsive to a competitive energy marketplace
may suffer erosion in market share, revenues and profits as competitors gain
access to their customers. In addition, SCANA's and SCE&G's generation
assets would be exposed to considerable financial risk in a deregulated electric
market. If market prices for electric generation do not produce adequate revenue
streams and the enabling legislation or regulatory actions do not provide for
recovery of the resulting stranded costs, a write-down in the value of the
related assets would be required.
The
Company and SCE&G are subject to risks associated with changes in business
climate which could increase and adversely affect revenues, results of
operations, cash flows and financial condition and could limit access to
capital.
Sales
and
sales growth is dependent upon the economic climate in the service territories
of the Company and SCE&G, which may be affected by regional, national or
even international economic factors. Some economic sectors important to our
customer base may be particularly affected. Adverse events, economic or
otherwise, may also affect the operations of key customers. The success of
local
and state governments in attracting new industry to our service territories
is
important to our growth in sales.
Factors
that generally could affect our ability to access capital include economic
conditions and our capital structure. Much of our business is capital intensive,
and achievement of our long-term growth targets is dependent, at least in part,
upon our ability to access capital at rates and on terms we determine to be
attractive. If our ability to access capital becomes significantly constrained,
our interest costs will likely increase and our financial condition and future
results of operations could be significantly harmed.
Problems
with operations could cause us to curtail or limit our ability to serve
customers or cause us to incur substantial costs, thereby adversely impacting
revenues, results of operations, cash flows and financial
condition.
Critical
processes or systems in the Company’s or SCE&G’s operations could become
impaired or fail from a variety of causes, such as equipment breakdown,
transmission line failure, information systems failure, and the effects of
a
pandemic or terrorist attack on our workforce or on the ability of vendors
and
suppliers to maintain services key to our operations.
In
particular, as the operator of power generation facilities, SCE&G could
incur problems such as the breakdown or failure of power generation equipment,
transmission lines, other equipment or processes which would result in
performance below assumed levels of output or efficiency. The failure of a
power
generation facility may result in SCE&G purchasing replacement power at
market rates. These purchases are subject to state regulatory prudency reviews
for recovery through rates.
Covenants
in certain financial instruments may limit SCANA's ability to pay dividends,
thereby adversely impacting the valuation of our common stock and our access
to
capital.
Our
assets consist primarily of investments in subsidiaries. Dividends on our common
stock depend on the earnings, financial condition and capital requirements
of
our subsidiaries, principally SCE&G, PSNC Energy and SEMI. Our ability to
pay dividends on our common stock may also be limited by existing or future
covenants limiting the right of our subsidiaries to pay dividends on their
common stock. Any significant reduction in our payment of dividends in the
future may result in a decline in the value of our common stock. Such a decline
in value could limit our ability to raise debt and equity capital.
A
significant portion of SCE&G's generating capacity is derived from nuclear
power, the use of which exposes us to regulatory, environmental and business
risks. These risks could increase our costs or otherwise constrain our business,
thereby adversely impacting our results of operations, cash flows and financial
condition.
The
V.C.
Summer nuclear plant, operated by SCE&G, provided approximately
5.0 million MWh, or 19% of our generation capacity, in 2006. As such,
SCE&G is subject to various risks of nuclear generation, which include the
following:
The
potential harmful effects on the environment and human health resulting from
a
release of radioactive materials in connection with the operation of nuclear
facilities and the storage, handling and disposal of radioactive
materials;
Limitations
on the amounts and types of insurance commercially available to cover losses
that might arise in connection with our nuclear operations or those of others
in
the United States;
Uncertainties
with respect to procurement of enriched uranium fuel;
Uncertainties
with respect to contingencies if insurance coverage is inadequate;
and
Uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their operating lives.
The
NRC
has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event
of
non-compliance, the NRC has the authority to impose fines or shut down a unit,
or both, depending upon its assessment of the severity of the situation, until
compliance is achieved. Revised safety requirements promulgated by the NRC
could
necessitate capital expenditures at nuclear plants such as ours. In addition,
although we have no reason to anticipate a serious nuclear incident, if a major
incident should occur at a domestic nuclear facility, it could harm our results
of operations, cash flows and financial condition. A major incident at a nuclear
facility anywhere in the world could cause the NRC to limit or prohibit the
operation or licensing of any domestic nuclear unit. Finally, in today's
environment, there is a heightened risk of terrorist attack on the nation's
nuclear facilities, which has resulted in increased security costs at our
nuclear plant.
Failure
to retain and attract key personnel could adversely affect the Company’s and
SCE&G’s operations and financial performance.
Implementation
of our strategic plan and growth strategy requires that we attract, retain
and
develop executive officers and other professional and technical employees with
the skills and experience necessary to successfully manage our operations and
grow our business. Competition for these employees is high, and in some cases
we
must compete for these employees on a regional or national basis. We may be
unable to attract and retain these personnel. Further, the Company’s or
SCE&G’s ability to construct or maintain generation or other assets requires
the availability of suitable skilled contractor personnel. We may be unable
to
obtain appropriate contractor personnel at the times and places
needed.
The
Company and SCE&G are subject to the risk that strategic decisions made by
us either do not result in a return of or on invested capital or might
negatively impact our competitive position, which can adversely impact our
results of operations, cash flows, financial position, and access to
capital.
From
time
to time, the Company and SCE&G make strategic decisions that may impact our
direction with regard to business opportunities, the services and technologies
offered to customers or that are used to serve customers, and the generating
plant and other infrastructure that form the basis of much of our business.
These strategic decisions may not result in a return of or on our invested
capital, and the effects of these strategic decisions may have long-term
implications that are not likely to be known to us in the short-term. In
addition, these strategic decisions, which could be adverse to the Company’s or
SCE&G’s interests, may have a negative effect on our results of operations,
cash flows and financial position, as well as limit our ability to access
capital.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None
ITEM
2. PROPERTIES
SCANA
owns no significant property other than the capital stock of each of its
subsidiaries. It holds, directly or indirectly, all of the capital stock of
each
of its subsidiaries except for the preferred stock of SCE&G. SCANA also has
an investment in one LLC which operates a cogeneration facility in Charleston,
South Carolina.
SCE&G's
bond indenture, securing the First Mortgage Bonds issued thereunder, constitutes
a direct mortgage lien on substantially all of its electric utility property.
GENCO's Williams Station is also subject to a first mortgage lien.
For
a
brief description of the properties of SCANA's other subsidiaries, which are
not
significant as defined in Rule 1-02 of Regulation S-X, see
Item 1, BUSINESS-SEGMENTS OF BUSINESS-Nonregulated Businesses.
The
following map indicates significant electric generation and natural gas
transmission properties, which are further described below. Natural gas
distribution properties in South Carolina and North Carolina, though not
depicted on the map, are also described below.
ELECTRIC
PROPERTIES
SCE&G
owns each of the electric generating facilities listed below unless otherwise
noted.
|
Facility
|
Present
Fuel Capability
|
Location
|
Year
In-Service
|
Net
Generating
Capacity
(Summer Rating) (MW)
|
|
Steam
Turbines
|
|
|
|
|
|
Summer(1)
|
Nuclear
|
Parr,
SC
|
1984
|
644
|
|
McMeekin
|
Coal/Gas
|
Irmo,
SC
|
1958
|
250
|
|
Canadys
|
Coal/Gas
|
Canadys,
SC
|
1962
|
416
|
|
Wateree
|
Coal
|
Eastover,
SC
|
1970
|
700
|
|
Williams(2)
|
Coal
|
Goose
Creek, SC
|
1973
|
615
|
|
Cope
|
Coal
|
Cope,
SC
|
1996
|
420
|
|
Cogen
South(3)
|
|
Charleston,
SC
|
1999
|
90
|
|
|
|
|
||
|
Combined
Cycle
|
|
|
||
|
Urquhart(4)
|
Coal/Gas/Oil
|
Beech
Island, SC
|
1953/2002
|
568
|
|
Jasper
|
Gas/Oil
|
Hardeeville,
SC
|
2004
|
880
|
|
|
|
|
||
|
Hydro(5)
|
|
|
||
|
Saluda
|
|
Irmo,
SC
|
1930
|
206
|
|
Fairfield
Pumped Storage
|
|
Parr,
SC
|
1978
|
576
|
(1) Represents
SCE&G's two-thirds portion of the Summer Station (one-third owned by Santee
Cooper).
(2) The
steam
unit at Williams Station is owned by GENCO.
(3) SCE&G
receives shaft horse power from Cogen South, LLC to operate SCE&G's
generator. Cogen South, LLC is
owned
50%
by SCANA and 50% by MeadWestvaco.
(4) Two
combined-cycle turbines burn natural gas or fuel oil to produce 341 MW of
electric generation and use exhaust
heat
to
power two 75 MW turbines at the Urquhart Generating Station. Unit 3 is a
coal-fired steam unit.
(5) SCE&G
also owns three other hydro units in South Carolina that were placed in service
in 1905 and 1914 and have
an
aggregate net generating capacity of 32 MW.
SCE&G
owns nine other combustion turbine peaking units fueled by gas and/or oil
located at various sites in SCE&G's service territory. These turbines were
placed in service at various times from 1961 to 1999 and have aggregate net
generating capacity of 365 MW.
SCE&G
owns 444 substations having an aggregate transformer capacity of
26.3 million KVA (kilovolt-ampere). The transmission system consists of
3,218 miles of lines, and the distribution system consists of 17,903 pole miles
of overhead lines and 5,608 trench miles of underground lines.
NATURAL
GAS DISTRIBUTION AND TRANSMISSION PROPERTIES
SCE&G’s
natural gas system consists of 15,144 miles of distribution mains and related
service facilities. In 2006, SCE&G purchased two LNG plants from SCPC, one
located near Charleston, South Carolina and the other in Salley, South Carolina.
The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied
equivalent of 980 MMCF of natural gas. The Salley facility can store the
liquefied equivalent of 900 MMCF of natural gas and has no liquefying
capabilities.
CGTC’s
natural gas system consists of 1,472 miles of transmission pipeline of up to
24
inches in diameter, which connect its transportation customers’ distribution
systems with the transmission systems of Southern Natural and Transco. CGTC’s
system also includes 18 miles of transmission pipeline of up to 20 inches in
diameter which transports natural gas from Port Wentworth and Elba Island,
Georgia to SCE&G’s Jasper County Electric Generating Station in South
Carolina.
PSNC
Energy’s natural gas system consists of 902 miles of transmission pipeline of up
to 24 inches in diameter that connect its distribution systems with Transco.
PSNC Energy's distribution system consists of 8,880 miles of distribution mains
and related service facilities. PSNC Energy owns one LNG plant with storage
capacity of 1,000 MMCF and the capacity to regasify approximately 100 MMCF
per
day. PSNC Energy also owns, through a wholly owned subsidiary, 33.21% of
Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline
in
North Carolina. In addition, PSNC Energy owns, through a wholly owned
subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates
a
liquefaction, storage and regasification facility in North
Carolina.
ITEM
3. LEGAL PROCEEDINGS
Certain
material legal proceedings and environmental and regulatory matters and
uncertainties, some of which remain outstanding at December 31, 2006, are
described below. These issues affect SCANA and, to the extent indicated, also
affect SCE&G.
Environmental
Matters
SCE&G
owns a decommissioned manufactured gas plant (MGP) site in the Calhoun Park
area
of Charleston, South Carolina. The site is currently being remediated for
contamination. SCE&G anticipates that the remaining remediation activities
will be completed in late 2007, with certain monitoring and other activities
continuing until 2011. As of December 31, 2006, SCE&G has spent
approximately $22.3 million to remediate the Calhoun Park site, and expects
to spend an additional $1.1 million prior to entering a monitoring and
reporting stage. In addition, the National Park Service of the Department of
the
Interior made an initial demand to SCE&G for payment of $9.1 million
for certain costs and damages relating to this site. SCE&G expects to
recover any cost arising from the remediation of this site through
rates.
SCE&G
owns three other decommissioned MGP sites in South Carolina which contain
residues of by-product chemicals. One of the sites has been remediated and
will
undergo routine monitoring until released by the South Carolina Department
of
Health and Environmental Control (DHEC). The other sites are currently being
investigated under work plans approved by DHEC. SCE&G anticipates that major
remediation activities for the three sites will be completed by 2011. As of
December 31, 2006, SCE&G had spent approximately $4.8 million
related to these three sites, and expects to spend an additional
$11.2 million. SCE&G expects to recover any cost arising from the
remediation of these sites through rates.
SCE&G
has been named, along with 29 others, by the United States Environmental
Protection Agency (EPA) as a potentially responsible party (PRP) at the Carolina
Transformer Superfund site located in Fayetteville, North Carolina. The
Carolina Transformer Company (CTC) conducted an electrical transformer
rebuilding and repair operation at the site from 1967 to 1984. During that
time, SCE&G occasionally used CTC for the repair of existing transformers,
purchase of new transformers and sale of used transformers. In 1984, EPA
initiated a cleanup of PCB-contaminated soil and groundwater at the site.
EPA reports that it has spent $36 million to date. Although a basis for
the allocation of clean-up costs among the PRPs is unclear, SCE&G does not
believe that its involvement at this site would result in an allocation of
costs
that would have a material adverse impact on its results of operations, cash
flows or financial condition. Any cost allocated to SCE&G arising from the
remediation of this site, net of insurance recoveries, if any, is expected
to be
recoverable through rates.
SCE&G
has been named, along with 53 others, by the EPA as a PRP at the Alternate
Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.
The EPA placed the site on the National Priorities List on April 19, 2006.
AER
conducted hazardous waste storage and treatment operations from 1975 to 2000,
when the site was abandoned. While operational, AER processed fuels from
waste oils, treated industrial coolants and oil/water emulsions, recycled
solvents and blended hazardous waste fuels. During that time, SCE&G
occasionally used AER for the processing of waste solvents, oily rags and oily
wastewater. EPA and the State of Georgia have documented that a release or
releases have occurred at the site leading to contamination of groundwater,
surface water and soils. EPA and the State of Georgia have conducted a
preliminary assessment and site inspection. The site has not been cleaned up
nor
has a cleanup cost been estimated. Although a basis for the allocation of
clean-up costs among the PRPs is unclear, SCE&G does not believe that its
involvement at this site would result in an allocation of costs that would
have
a material adverse impact on its results of operations, cash flows or financial
condition. Any cost allocated to SCE&G arising from the remediation of this
site, net of insurance recoveries, if any, is expected to be recoverable through
rates.
PSNC
Energy is responsible for environmental cleanup at five sites in North Carolina
on which MGP residuals are present or suspected. PSNC Energy's remediation
costs
for these sites will depend on a number of factors, such as actual site
conditions, third-party claims and recoveries from other PRPs. PSNC Energy
has
recorded a liability and associated regulatory asset of approximately
$6.9 million, which reflects its estimated remaining liability at
December 31, 2006. SCANA and PSNC Energy believe that any cost allocated to
PSNC Energy arising from the remediation of these sites is expected to be
recoverable through gas rates.
Litigation
In
August
2003, SCE&G was served as a co-defendant in a purported class action lawsuit
styled as Collins v. Duke Energy Corporation, Progress Energy Services Company,
and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth
Judicial Circuit. Since that time, the plaintiffs have dismissed defendants
Duke
Energy and Progress Energy and are proceeding against SCE&G only. The
plaintiffs are seeking damages for the alleged improper use of electric
transmission and distribution easements but have not asserted a dollar amount
for their claims. Specifically, the plaintiffs contend that the licensing of
attachments on electric utility poles, towers and other facilities to
non-utility third parties or telecommunication companies for other than the
electric utility’s internal use along the electric transmission and distribution
line rights-of-way constitutes a trespass. It is anticipated that this case
may
not go to trial before 2008. SCANA and SCE&G are confident of the propriety
of SCE&G’s actions and intend to mount a vigorous defense. SCANA and
SCE&G further believe that the resolution of these claims will not have a
material adverse impact on their results of operations, cash flows or financial
condition.
In
May 2004, SCANA and SCE&G were served with a purported class action
lawsuit styled as Douglas E. Gressette, individually and on behalf of other
persons similarly situated v. South Carolina Electric & Gas Company and
SCANA Corporation. The case was filed in South Carolina's Circuit Court of
Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges SCANA and
SCE&G made improper use of certain easements and rights-of-way by allowing
fiber optic communication lines and/or wireless communication equipment to
transmit communications other than SCANA’s and SCE&G’s electricity-related
internal communications. The plaintiff asserted causes of action for unjust
enrichment, trespass, injunction and declaratory judgment. The plaintiff did
not
assert a specific dollar amount for the claims. SCANA and SCE&G believe
their actions are consistent with governing law and the applicable documents
granting easements and rights-of-way. The Circuit Court granted SCANA’s and
SCE&G’s motion to dismiss and issued an order dismissing the case in June
2005. The
plaintiff appealed to the South Carolina Supreme Court. The Supreme Court
overruled the Circuit Court in October 2006 and returned the case to the Circuit
Court for further consideration. It is anticipated that this case may not go
to
trial before 2008. SCANA
and
SCE&G
will
continue to mount a vigorous defense and believe that the resolution of these
claims will not have a material adverse impact on their results of operations,
cash flows or financial condition.
A
complaint was filed on October 22, 2003 against SCE&G by the State of
South Carolina alleging that SCE&G violated the Unfair Trade Practices Act
by charging municipal franchise fees to some customers residing outside a
municipality's limits. The complaint alleged that SCE&G failed to obey,
observe or comply with the lawful order of the SCPSC by charging franchise
fees
to those not residing within a municipality. The complaint sought restitution
to
all affected customers and penalties of up to $5,000 for each separate
violation. The claim against SCE&G has been settled by an agreement between
the parties, and the settlement has been approved by the court. The allegations
were also the subject of a purported class action lawsuit filed in
December 2003, against Duke Energy Corporation, Progress Energy Services
Company and SCE&G (styled Edwards v. SCE&G), but that case has been
dismissed by the plaintiff. In addition, SCE&G filed a petition with the
SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The
petition requests that the SCPSC exercise its jurisdiction to investigate the
operation of the municipal franchise fee collection requirements applicable
to
SCE&G's electric and gas service, to approve SCE&G's efforts to correct
any past franchise fee billing errors, to adopt improvements in the system
which
will reduce such errors in the future, and to adopt any regulation that the
SCPSC deems just and proper to regulate the franchise fee collection process.
A
hearing on this petition has not been scheduled. SCANA and SCE&G believe
that the resolution of these matters will not have a material adverse impact
on
their results of operations, cash flows or financial condition.
Settlement
Related to Power Marketing Practices
On
January 18, 2007, the Federal Energy Regulatory Commission (FERC) approved
a
settlement with SCE&G regarding the use of SCE&G’s electric transmission
system by its power marketing division. SCE&G identified, investigated and
self-reported instances of improper utilization of network transmission
services, rather than point-to-point transmission services, for purchases and
sales of electricity in violation of SCE&G’s open access transmission tariff
and applicable FERC orders under the Federal Power Act that prohibit the use
of
network transmission service in support of certain “off-system” sales.
As
part
of the settlement, SCE&G agreed that it would not retain any benefit derived
from the transactions. SCE&G paid a $9 million penalty to the U.S. Treasury.
Additionally, SCE&G agreed to credit
an
additional $1.4 million to benefit retail native load ratepayers and SCE&G’s
non-affiliated firm transmission customers. The credit to the retail native
load
ratepayers was applied toward the fuel clause mechanism in January 2007. The
credit to the non-affiliated firm transmission customers was refunded directly
to those customers. An additional $0.4 million was credited to transmission
revenue to the benefit of SCE&G’s retail rate payers. The effects of the
settlement were accrued in 2006.
SCANA
and
SCE&G are also engaged in various other claims and litigation incidental to
their business operations which management anticipates will be resolved without
material loss.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
Not
Applicable.
The
executive officers are elected at the annual meeting of the Board of Directors,
held immediately after the annual meeting of shareholders, and hold office
until
the next such annual meeting, unless (1) a resignation is submitted, (2) the
Board of Directors shall otherwise determine or (3) as provided in the By-laws
of SCANA. Positions held are for SCANA and all subsidiaries unless otherwise
indicated.
|
Name
|
Age
|
Positions
Held During Past Five Years
|
Dates
|
|
|
|
|
|
|
William
B. Timmerman
|
60
|
Chairman
of the Board, President and Chief Executive Officer
|
*-present
|
|
Jimmy
E. Addison
|
46
|
Senior
Vice President and Chief Financial Officer
Vice
President-Finance
|
2006-present
*-2006
|
|
Joseph
C. Bouknight
|
54
|
Senior
Vice President-Human Resources
Vice
President Human Resources-Dan River, Inc.-Danville, VA
|
2004-present
*-2004
|
|
George
J. Bullwinkel
|
58
|
President
and Chief Operating Officer-SEMI
President
and Chief Operating Officer-SCI and ServiceCare
President
and Chief Operating Officer-SCPC and SCG Pipeline
|
2004-present
*-present
*-2004
|
|
Sarena
D. Burch
|
49
|
Senior
Vice President-Fuel Procurement and Asset Management-SCE&G
and
PSNC
Energy
Senior
Vice President-Fuel Procurement and Asset Management-SCPC
Deputy
General Counsel and Assistant Secretary
|
2003-present
2003-2006
*-2003
|
|
Stephen
A. Byrne
|
47
|
Senior
Vice President-Generation, Nuclear and Fossil Hydro-SCE&G
Senior
Vice President-Nuclear Operations
|
2004-present
*-2004
|
|
P.
V. Fant
|
53
|
Senior
Vice President-Transmission Services
President
and Chief Operating Officer-CGTC (formerly SCPC and SCG)
Executive
Vice President-SCPC and SCG Pipeline
|
2004-present
2004-present
*-2004
|
|
Kevin
B. Marsh
|
51
|
President
and Chief Operating Officer - SCE&G
Senior
Vice President and Chief Financial Officer
President
and Chief Operating Officer-PSNC Energy
|
2006-present
*-2006
*-2003
|
|
Charles
B. McFadden
|
62
|
Senior
Vice President-Governmental Affairs and Economic Development-
SCANA
Services
Vice
President-Governmental Affairs and Economic Development-SCANA
Services
|
2003-present
*-2003
|
|
Francis
P. Mood, Jr.
|
69
|
Senior
Vice President, General Counsel and Assistant Secretary
Attorney,
Haynsworth Sinkler Boyd, P.A.-Columbia, SC
|
2005-present
*-2005
|
*
Indicates position held at least since March 1, 2002.
PART
II
ITEM
5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS,
AND
ISSUER PURCHASES OF EQUITY SECURITIES
COMMON
STOCK INFORMATION
SCANA
Corporation:
Price
Range (New York Stock Exchange Composite Listing):
|
|
2006
|
2005
|
|||||||
|
|
4th Qtr.
|
3rd Qtr.
|
2nd Qtr.
|
1st Qtr.
|
4th Qtr.
|
3rd Qtr.
|
2nd Qtr.
|
1st Qtr.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
$42.43
|
$41.65
|
$40.41
|
$41.42
|
$43.37
|
$43.65
|
$43.30
|
$40.04
|
|
|
Low
|
$39.55
|
$38.35
|
$36.92
|
$39.02
|
$37.79
|
$39.90
|
$36.56
|
$36.70
|
|
SCANA
common stock trades on The New York Stock Exchange, using the ticker symbol
SCG.
Newspaper stock listings use the name SCANA. At February 20, 2007 SCANA
common stock totaling 116,664,933 shares were held by approximately 34,326
stockholders of record. For a summary of equity securities issuable under
SCANA's compensation plans at December 31, 2006, see Item 12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS.
SCANA
declared quarterly dividends on its common stock of $.42 per share in 2006
and
$.39 per share in 2005. On February 15, 2007, SCANA increased the quarterly
cash dividend rate on SCANA common stock to $.44 per share, an increase of
4.8%.
The new dividend is payable April 1, 2007 to stockholders of record on
March 9, 2007. For a discussion of provisions that could limit the payment
of cash dividends, see Note 6 to the consolidated financial statements for
SCANA and SCE&G.
SCE&G: All
of
SCE&G's common stock is owned by SCANA and has no market. During 2006 and
2005 SCE&G paid $151.5 million and $150.5 million, respectively,
in cash dividends to SCANA.
SECURITIES
RATINGS (As of February 20, 2007)
|
SCANA
|
SCE&G
|
|||||
|
Rating
Agency
|
Senior
Unsecured
|
Senior
Secured
|
Senior
Unsecured
|
Preferred
Stock
|
Commercial
Paper
|
|
|
Moody's
|
A3
|
A1
|
A2
|
Baa1
|
P-1
|
|
|
Standard
& Poors (S&P)
|
BBB+
|
A-
|
BBB+
|
BBB
|
A-2
|
|
|
Fitch
|
A-
|
A+
|
A
|
A
|
F-1
|
|
All
ratings carry a stable outlook. For additional information regarding these
securities, see Notes 4, 5 and 7 to the consolidated financial statements
for SCANA and SCE&G.
Securities
ratings used by Moody's, Standard & Poors and Fitch are as
follows:
|
Long-term
(investment grade)
|
Short-term
|
||||
|
Moody's
(1)
|
S&P
(2)
|
Fitch
(2)
|
Moody's
|
S&P
|
Fitch
|
|
Aaa
|
AAA
|
AAA
|
Prime-1
(P-1)
|
A-1
|
F-1
|
|
Aa
|
AA
|
AA
|
Prime-2
(P-2)
|
A-2
|
F-2
|
|
A
|
A
|
A
|
Prime-3
(P-3)
|
A-3
|
F-3
|
|
Baa
|
BBB
|
BBB
|
Not
Prime
|
B
|
B
|
|
C
|
C
|
||||
|
D
|
D
|
||||
(1)
Additional Modifiers: 1, 2, 3 (Aa to Baa)
(2)
Additional Modifiers: +, - (AA to BBB)
A
security rating should be evaluated independently of other ratings and is not
a
recommendation to buy, sell or hold securities. The assigning rating
organization may revise or withdraw its security ratings at any
time.
ITEM
6. SELECTED FINANCIAL AND OTHER STATISTICAL
DATA
|
|
SCANA
|
SCE&G
|
|||||||||||||||||||||||||||||
|
As
of or for the Year Ended December 31,
|
2006
|
2005
|
2004
|
2003
|
2002
|
2006
|
2005
|
2004
|
2003
|
2002
|
|||||||||||||||||||||
|
|
(Millions
of dollars, except statistics and per share
amounts)
|
||||||||||||||||||||||||||||||
|
Statement
of Operation Data
|
|
|
|
|
|
|
|||||||||||||||||||||||||
|
Operating
Revenues
|
$
|
4,563
|
$
|
4,777
|
$
|
3,885
|
$
|
3,416
|
$
|
2,954
|
$
|
2,391
|
$
|
2,421
|
$
|
2,089
|
$
|
1,832
|
$
|
1,683
|
|||||||||||
|
Operating
Income
|
603
|
436
|
596
|
551
|
514
|
468
|
312
|
475
|
440
|
431
|
|||||||||||||||||||||
|
Other
Income (Expense)
|
(164
|
)
|
(162
|
)
|
(219
|
)
|
(138
|
)
|
(397
|
)
|
(121
|
)
|
(121
|
)
|
(111
|
)
|
(101
|
)
|
(90
|
)
|
|||||||||||
|
Income
Before Cumulative Effect
of
Accounting Change
|
304
|
320
|
257
|
282
|
88
|
230
|
258
|
232
|
220
|
219
|
|||||||||||||||||||||
|
Net
Income (Loss) (1)
|
310
|
320
|
257
|
282
|
(142
|
)
|
234
|
258
|
232
|
220
|
219
|
||||||||||||||||||||
|
Common
Stock Data
|
|||||||||||||||||||||||||||||||
|
Weighted
Average Number of Common Shares
|
|||||||||||||||||||||||||||||||
|
Outstanding
(Millions)
|
115.8
|
113.8
|
111.6
|
110.8
|
106.0
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
|||||||||||||||||||||
|
Basic
and Diluted Earnings (Loss)
Per
Share (1)
|
$
|
2.68
|
$
|
2.81
|
$
|
2.30
|
$
|
2.54
|
$
|
(1.34
|
)
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
|||||||||||||||
|
Dividends
Declared Per Share of Common Stock
|
$
|
1.68
|
$
|
1.56
|
$
|
1.46
|
$
|
1.38
|
$
|
1.30
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
||||||||||||||||
|
Balance
Sheet Data
|
|||||||||||||||||||||||||||||||
|
Utility
Plant, Net
|
$
|
7,007
|
$
|
6,734
|
$
|
6,762
|
$
|
6,417
|
$
|
5,474
|
$
|
5,748
|
$
|
5,580
|
$
|
5,621
|
$
|
5,293
|
$
|
4,729
|
|||||||||||
|
Total
Assets
|
9,817
|
9,519
|
9,006
|
8,458
|
8,074
|
7,626
|
7,366
|
6,985
|
6,628
|
5,958
|
|||||||||||||||||||||
|
Capitalization:
|
|||||||||||||||||||||||||||||||
|
Common equity
|
$
|
2,846
|
$
|
2,677
|
$
|
2,451
|
$
|
2,306
|
$
|
2,177
|
$
|
2,457
|
$
|
2,362
|
$
|
2,164
|
$
|
2,043
|
$
|
1,966
|
|||||||||||
|
Preferred Stock (Not subject to
purchase or sinking funds)
|
106
|
106
|
106
|
106
|
106
|
106
|
106
|
106
|
106
|
106
|
|||||||||||||||||||||
|
Preferred Stock, net (Subject to
purchase or sinking funds)
|
8
|
8
|
9
|
9
|
9
|
8
|
8
|
9
|
9
|
9
|
|||||||||||||||||||||
|
SCE&G-Obligated Mandatorily
Redeemable
|
|||||||||||||||||||||||||||||||
|
Preferred Securities of SCE&G
Trust I
|
-
|
-
|
-
|
-
|
50
|
-
|
-
|
-
|
-
|
50
|
|||||||||||||||||||||
|
Long-term Debt, net
|
3,067
|
2,948
|
3,186
|
3,225
|
2,834
|
2,008
|
1,856
|
1,981
|
2,010
|
1,604
|
|||||||||||||||||||||
|
Total
Capitalization
|
$
|
6,027
|
$
|
5,739
|
$
|
5,752
|
$
|
5,646
|
$
|
5,176
|
$
|
4,579
|
$
|
4,332
|
$
|
4,260
|
$
|
4,168
|
$
|
3,735
|
|||||||||||
|
Other
Statistics
|
|||||||||||||||||||||||||||||||
|
Electric:
|
|||||||||||||||||||||||||||||||
|
Customers (Year-End)
|
623,402
|
609,971
|
585,264
|
570,940
|
560,224
|
623,453
|
610,025
|
585,326
|
570,994
|
560,248
|
|||||||||||||||||||||
|
Total sales (Million KWh)
|
24,523
|
25,309
|
25,031
|
22,516
|
23,085
|
24,542
|
25,327
|
25,050
|
22,531
|
23,085
|
|||||||||||||||||||||
|
Generating capability-Net MW
(Year-End)
|
5,749
|
5,808
|
5,817
|
4,880
|
4,866
|
5,749
|
5,808
|
5,817
|
4,880
|
4,866
|
|||||||||||||||||||||
|
Territorial peak demand-Net MW
|
4,820
|
4,820
|
4,574
|
4,474
|
4,404
|
4,820
|
4,820
|
4,574
|
4,474
|
4,404
|
|||||||||||||||||||||
|
Regulated
Gas:
|
|||||||||||||||||||||||||||||||
|
Customers (Year-End)
|
738,317
|
716,794
|
693,172
|
672,849
|
657,950
|
297,165
|
291,607
|
284,355
|
278,463
|
274,334
|
|||||||||||||||||||||
|
Sales, excluding transportation
(Thousand Therms)
|
996,173
|
1,106,526
|
1,124,555
|
1,205,730
|
1,354,400
|
403,489
|
410,700
|
399,601
|
399,392
|
398,991
|
|||||||||||||||||||||
|
Retail
Gas Marketing:
|
|||||||||||||||||||||||||||||||
|
Retail customers (Year-End)
|
482,822
|
479,382
|
472,468
|
415,573
|
374,872
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
|||||||||||||||||||||
|
Firm customer deliveries
(Thousand Therms)
|
335,896
|
379,913
|
379,712
|
356,256
|
337,858
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
|||||||||||||||||||||
|
Nonregulated interruptible customer
deliveries (Thousand
Therms)
|
1,239,926 | 1,010,066 | 917,875 | 735,902 | 852,608 | n/a | n/a | n/a | n/a | n/a | |||||||||||||||||||||
|
1,239,926
|
1,010,066
|
917,875
|
735,902
|
852,608
|
n/a
|
n/a
|
n/a
|
n/a
|
n/a
|
||||||||||||||||||||||
(1)
Reflects the 2006 adoption of Statement of Financial Accounting Standards (SFAS)
123(R), recorded as the cumulative effect of
an accounting change
of $6 million for SCANA and $4 million for SCE&G, and the write-down
in 2002 of $230 million
for SCANA for goodwill impairment, recorded as the
cumulative effect of an accounting change, upon adoption of
SFAS 142.
|
|
|
Page
|
|
|
|
|
|
|
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
27
|
||
|
|
|
Overview
|
27
|
|
|
|
Results
of Operations
|
30
|
|
|
|
Liquidity
and Capital Resources
|
37
|
|
|
|
Environmental
Matters
|
40
|
|
|
|
Regulatory
Matters
|
42
|
|
|
|
Critical
Accounting Policies and Estimates
|
43
|
|
|
|
Other
Matters
|
45
|
|
|
|
|
|
|
Quantitative
and Qualitative Disclosures About Market Risk
|
46
|
||
|
|
|
|
|
|
Financial
Statements and Supplementary Data
|
48
|
||
|
|
|
Report
of Independent Registered Public Accounting Firm
|
48
|
|
|
|
Consolidated
Balance Sheets
|
49
|
|
|
|
Consolidated
Statements of Income
|
51
|
|
|
|
Consolidated
Statements of Cash Flows
|
52
|
|
|
|
Consolidated
Statements of Changes in Common Equity and Comprehensive Income
|
53
|
|
|
|
Notes
to Consolidated Financial Statements
|
54
|
|
|
|
|
|
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS
OF
OPERATIONS
SCANA,
through its wholly owned regulated subsidiaries, is primarily engaged in the
generation, transmission, distribution and sale of electricity in parts of
South
Carolina and the purchase, transmission and sale of natural gas in portions
of
North Carolina and South Carolina. Through a wholly owned nonregulated
subsidiary, SCANA markets natural gas to retail customers in Georgia and to
wholesale customers primarily in the southeast. Other wholly owned nonregulated
subsidiaries perform power plant management and maintenance services, provide
fiber optic and other telecommunications services, and provide service contracts
to homeowners on certain home appliances and heating and air conditioning units.
Additionally, a service company subsidiary of SCANA provides administrative,
management and other services to the other subsidiaries.
The
following map indicates areas where the Company’s significant business segments
conducted their activities, as further described in this overview
section.
The
following percentages reflect revenues and net income earned by the Company’s
regulated and nonregulated businesses and the percentage of total assets held
by
them.
|
%
of Revenues
|
|
2006
|
2005
|
2004
|
|
||||||
|
Regulated
|
|
|
69
|
%
|
69
|
%
|
|
71
|
%
|
||
|
Nonregulated
|
|
|
31
|
%
|
31
|
%
|
|
29
|
%
|
||
|
|
|
|
|
|
|
|
|
||||
|
%
of Net Income (Loss)
|
|
|
2006(b
|
)
|
2005
|
2004(a
|
)
|
||||
|
Regulated
|
|
|
89
|
%
|
|
92
|
%
|
|
106
|
%
|
|
|
Nonregulated
|
|
|
11
|
%
|
|
8
|
%
|
|
(6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
%
of Assets
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
Regulated
|
|
|
93
|
%
|
94
|
%
|
|
94
|
%
|
||
|
Nonregulated
|
|
|
7
|
%
|
6
|
%
|
|
6
|
%
|
||
(a)
In
2004, net income for regulated businesses totaled $272.0 million and net
loss for nonregulated businesses totaled $14.9 million. Net loss for
nonregulated businesses included impairments and losses ($29.8 million, net
of tax) recognized on the sale of certain of the Company’s telecommunications
investments and a charge ($11.1 million, net of taxes) related to pending
litigation associated with the Company’s 1999 sale of its propane assets.
(b)
In
2006, net income for non-regulated businesses included a reduction of the
litigation accrual referred to above upon the settlement of that litigation.
See
Results of Operations for more information.
Key
earnings drivers for the Company over the next five years will be additions
to
utility rate base at South Carolina Electric & Gas Company (SCE&G) and
Public Service Company of North Carolina, Incorporated (PSNC Energy), consisting
primarily of capital expenditures for environmental facilities, new generating
capacity and system expansion. Other factors that will impact future earnings
growth include the regulatory environment, customer growth in each of the
regulated utility businesses, consistent earnings growth in the natural gas
marketing business in Georgia and controlling the growth of operation and
maintenance expenses.
Electric
Operations
The
electric operations segment is comprised of the electric operations of
SCE&G, South Carolina Generating Company, Inc (GENCO) and South Carolina
Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation,
transmission, distribution and sale of electricity in South Carolina. At
December 31, 2006 SCE&G provided electricity to 623,400 customers in an
area covering nearly 17,000 square miles. GENCO owns and operates a coal-fired
generation station and sells electricity solely to SCE&G. Fuel Company
acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel
and emission allowance requirements.
Operating
results for electric operations are primarily driven by customer demand for
electricity, the ability to control costs and rates allowed to be charged to
customers. Embedded in the rates charged to customers is an allowed regulatory
return on equity. SCE&G’s allowed return on equity is not to exceed 11.4%,
with rates set at 10.7%. Demand for electricity is primarily affected by
weather, customer growth and the economy. SCE&G is able to recover the
cost of fuel used in electric generation through retail customers' bills, but
increases in fuel costs affect electric prices and, therefore, the competitive
position of electricity against other energy sources.
Legislative
and regulatory initiatives, including the Energy Policy Act of 2005 (the “Energy
Policy Act”) also could significantly impact the results of operations and cash
flows for the electric operations segment. The Energy Policy Act became law
in
August 2005, and it provides, among other things, for the establishment of
an
electric reliability organization (ERO) to propose and enforce mandatory
reliability standards for transmission systems, for procedures governing
enforcement actions by the ERO and FERC and for procedures under which the
ERO
may delegate authority to a regional entity to enforce reliability
standards.
In
February 2006 FERC issued final rules to implement the electric reliability
provisions of the Energy Policy Act. The Company is reviewing these rules and
monitoring their implementation to determine the impact they may have on
SCE&G’s access to or cost of power for its native load customers and for its
marketing of power outside its service territory. The Company cannot predict
when or if FERC will advance other regulatory initiatives related to the
national energy market or what conditions such initiatives would impose on
utilities.
New
legislation may also impose stringent requirements on power plants to reduce
emissions of sulfur dioxide, nitrogen oxides and mercury. It is also possible
that new initiatives will be introduced to reduce carbon dioxide emissions.
The
Company cannot predict whether such legislation will be enacted, and if it
is,
the conditions it would impose on utilities.
Gas
Distribution
The
gas
distribution segment is comprised of the local distribution operations of
SCE&G and PSNC Energy, and is primarily engaged in the purchase,
transmission and sale of natural gas to retail customers in portions of North
Carolina and South Carolina. At December 31, 2006 this segment provided
natural gas to 738,500 customers in areas covering 35,000 square
miles.
Operating
results for gas distribution are primarily influenced by customer demand for
natural gas, the ability to control costs and allowed rates to be charged to
customers. Embedded in the rates charged to customers is an allowed regulatory
return on equity.
Demand
for natural gas is primarily affected by weather, customer growth, the economy
and, for commercial and industrial customers, the availability and price of
alternate fuels. Natural gas competes with electricity, propane and heating
oil
to serve the heating and, to a lesser extent, other household energy needs
of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane
or
fuel oil. Natural gas competes with these alternate fuels based on price. As
a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect price and impact the Company’s ability to retain
large commercial and industrial customers. Significant supply disruptions did
occur in September and October 2005 as a result of hurricane activity in the
Gulf of Mexico, resulting in the curtailment during the period of most large
commercial and industrial customers with interruptible supply agreements. While
supply disruptions were not experienced in 2006 or in January or February of
2007, the price of natural gas remains volatile and has resulted in short-term
competitive pressure. The long-term impact of volatile gas prices and gas supply
has not been determined.
Gas
Transmission
Effective
November 1, 2006, SCG Pipeline merged into SCPC, and the merged company changed
its name to Carolina Gas Transmission Corporation (CGTC). CGTC operates an
open
access, transportation-only interstate pipeline company regulated by FERC.
CGTC’s operating results are primarily influenced by customer demand for natural
gas, the ability to control costs and allowed rates to be charged to customers.
Demand for CGTC’s services is closely linked to demand for natural gas and is
affected by the price of alternate fuels and customer growth. CGTC provides
transportation services to SCE&G for its gas distribution customers and for
certain electric generation needs and to SCANA Energy Marketing, Inc. (SEMI)
for
natural gas marketing. CGTC also provides transportation services to other
natural gas utilities, municipalities and county gas authorities and to
industrial customers.
Prior
to
the merger, the gas transmission segment was comprised solely of SCPC, which
owned and operated an intrastate pipeline engaged in the purchase, transmission
and sale of natural gas on a wholesale basis to distribution companies
(including SCE&G) and industrial customers throughout most of South
Carolina. SCPC’s operating results were primarily influenced by customer demand
for natural gas, the ability to control costs and allowed rates to be charged
to
customers.
Retail
Gas Marketing
SCANA
Energy, a division of SEMI, comprises the retail gas marketing segment. This
segment markets natural gas to over 475,000 customers (as of December 31,
2006) throughout Georgia. SCANA Energy’s total customer base represents over a
30% share of the approximately 1.5 million customers in Georgia’s deregulated
natural gas market. SCANA Energy remains the second largest natural gas marketer
in the state. SCANA Energy’s competitors include affiliates of other large
energy companies with experience in Georgia’s energy market as well as several
electric membership cooperatives. SCANA Energy’s ability to maintain its market
share depends on the prices it charges customers relative to the prices charged
by its competitors, its ability to continue to provide high levels of customer
service and other factors. In addition, the pipeline capacity available for
Energy Marketing to serve industrial and other customers is tied to the market
share held by SCANA Energy in the retail market.
As
Georgia’s regulated provider, SCANA Energy serves low-income customers and
customers unable to obtain or maintain natural gas service from other marketers
at rates approved by the Georgia Public Service Commission (GPSC), and it
receives funding from the Universal Service Fund for some of the bad debt
associated with the low-income group. SCANA Energy’s service as Georgia’s
regulated provider of natural gas ends August 31, 2007. In February 2007, the
GPSC initiated a request for proposal (RFP) bidding process which may be used
to
select a regulated provider for a new term. Notwithstanding that process, in
which SCANA Energy is expected to participate, the GPSC may elect to extend
SCANA Energy’s current contract term by one year. SCANA Energy files financial
and other information periodically with the GPSC, and such information is
available at www.psc.state.ga.us.
At
December 31, 2006, SCANA Energy’s regulated division served over 90,000
customers.
SCANA
Energy and SCANA’s other natural gas distribution and marketing segments
maintain gas inventory and also utilize forward contracts and financial
instruments, including futures contracts and options, to manage their exposure
to fluctuating commodity natural gas prices. See Note 9 to the consolidated
financial statements. As a part of this risk management process, at any given
time, a portion of SCANA’s projected natural gas needs has been purchased or
otherwise placed under contract. Since SCANA Energy operates in a competitive
market, it may be unable to sustain its current levels of customers and/or
pricing, thereby reducing expected margins and profitability. Further, there
can
be no assurance that Georgia’s gas delivery regulatory framework will remain
unchanged as dynamic market conditions evolve.
Energy
Marketing
The
divisions of SEMI, excluding SCANA Energy, comprise the energy marketing
segment. This segment markets natural gas primarily in the southeast and
provides energy-related risk management services to producers and
customers.
The
operating results for energy marketing are primarily influenced by customer
demand for natural gas and the ability to control costs. Demand for natural
gas
is primarily affected by the price of alternate fuels and customer
growth.
The
Company’s reported earnings are determined in accordance with GAAP. Management
believes that, in addition to reported earnings under GAAP, the Company’s
GAAP-adjusted net earnings from operations provides a meaningful representation
of its fundamental earnings power and can aid in performing period-over-period
financial analysis and comparison with peer group data. In management’s opinion,
GAAP-adjusted net earnings from operations is a useful indicator of the
financial results of the Company’s primary businesses. This measure is also a
basis for management’s provision of earnings guidance and growth projections,
and it is used by management in making resource allocation and other budgetary
and operational decisions. This non-GAAP performance measure is not intended
to
replace the GAAP measure of net earnings, but is offered as a supplement to
it.
A reconciliation of reported (GAAP) earnings per share to GAAP-adjusted net
earnings from operations per share, as well as cash dividend information, is
provided in the table below:
|
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Reported
(GAAP) earnings per share
|
|
$
|
2.68
|
$
|
2.81
|
|
$
|
2.30
|
|
|
|
Add
(Deduct):
|
|
|
|
|
|
|
|
|
||
|
Cumulative
effect of accounting change, net of tax
|
(.05
|
)
|
-
|
-
|
||||||
|
Charge
(reduction in charge) related to propane litigation
|
|
|
(.04
|
)
|
|
-
|
|
|
.10
|
|
|
Gains
from sales of telecommunications investments
|
|
|
-
|
|
(.03
|
)
|
|
-
|
||
|
Losses
from sales of telecommunications investments
|
|
|
-
|
|
-
|
|
|
.14
|
|
|
|
Telecommunications
investment impairments
|
|
|
-
|
|
-
|
|
|
.13
|
|
|
|
GAAP-adjusted
net earnings from operations per share
|
|
$
|
2.59
|
$
|
2.78
|
|
$
|
2.67
|
|
|
|
Cash
dividends declared (per share)
|
|
$
|
1.68
|
$
|
1.56
|
|
$
|
1.46
|
|
|
Discussion
of above adjustments:
The
cumulative effect of an accounting change in 2006 resulted from the Company’s
adoption of Statement of Financial Accounting Standard (SFAS) 123 (revised
2004), “Share-Based
Payment”
(SFAS
123(R)).
The
charge related to propane litigation recognized in 2004 resulted from an
unfavorable verdict in a case in which an unsuccessful bidder for the purchase
of certain of the Company’s propane gas assets in 1999 alleged breach of
contract and related claims. The litigation was settled in 2006 for an amount
that was less than had been previously accrued. See also Note 10 to the
consolidated financial statements.
Realized
gains in 2005 and realized losses in 2004 were recognized on sales of
telecommunications investments. Unrealized impairments on certain of these
investments were recognized in 2004. All significant telecommunications
investments have now been monetized.
Management
believes that all of the above adjustments are appropriate in determining the
non-GAAP financial performance measure. Management utilizes such measure itself
in exercising budgetary control, managing business operations and determining
eligibility for certain incentive compensation payments. Such non-GAAP measure
is based on management’s decision that the passive telecommunications
investments were not a part of the Company’s core businesses and would not be
available to provide earnings on a long-term basis. The non-GAAP measure also
provides a consistent basis upon which to measure performance by excluding
the
effects on per share earnings of transactions involving the Company’s
telecommunications investments and the litigation charge (and reduction) related
to the sale of a prior business.
Pension
Income
Pension
income was recorded on the Company’s financial statements as
follows:
|
Millions
of dollars
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Income
Statement Impact:
|
|
|
|
|
|
|
|
|
|
|
|
Reduction
in employee benefit costs
|
|
$
|
0.7
|
$
|
4.3
|
|
$
|
2.9
|
||
|
Other
income
|
|
|
12.3
|
|
11.9
|
|
|
10.8
|
|
|
|
Balance
Sheet Impact:
|
|
|
|
|
|
|
|
|
||
|
Reduction
in capital expenditures
|
|
|
0.3
|
|
1.3
|
|
|
1.0
|
||
|
Component
of amount due to Summer Station co-owner
|
|
|
0.2
|
|
0.6
|
|
|
0.4
|
||
|
Total
Pension Income
|
|
$
|
13.5
|
$
|
18.1
|
|
$
|
15.1
|
|
|
For
the
last several years, the market value of the Company’s retirement plan (pension)
assets has exceeded the total actuarial present value of accumulated plan
benefits. Among the reasons 2006’s income was lower than 2005’s was a reduction
of the assumed rate of return on plan assets from 9.25% to 9%. See also the
discussion of pension accounting in Critical Accounting Policies and
Estimates.
Allowance
for Funds Used During Construction (AFC)
AFC
is a
utility accounting practice whereby a portion of the cost of both equity and
borrowed funds used to finance construction (which is shown on the balance
sheet
as construction work in progress) is capitalized. The Company includes an equity
portion of AFC in nonoperating income and a debt portion of AFC in interest
charges (credits) as noncash items, both of which have the effect of increasing
reported net income. AFC represented approximately 2.0% of income before income
taxes in 2006, 1.4% in 2005 and 6.8% in 2004. The lower level of AFC for 2005
is
primarily due to reductions in the levels of capital expenditures subsequent
to
the completion of the Jasper County Electric Generation Station in May 2004
and
completion of the Lake Murray back-up dam project in May 2005.
Electric
Operations
Electric
Operations is comprised of the electric operations of SCE&G, GENCO and Fuel
Company. Electric operations sales margins (including transactions with
affiliates) were as follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Operating
revenues
|
|
$
|
1,877.6
|
(1.6
|
)%
|
$
|
1,908.3
|
|
|
13.1
|
%
|
$
|
1,687.7
|
|
||
|
Less:
Fuel used in generation
|
|
|
615.1
|
(0.5
|
)%
|
|
618.3
|
|
|
32.4
|
%
|
|
466.9
|
|
||
|
Purchased
power
|
|
|
27.5
|
(26.1
|
)%
|
|
37.2
|
|
|
(26.6
|
)%
|
|
50.7
|
|
||
|
Margin
|
|
$
|
1,235.0
|
(1.4
|
)%
|
$
|
1,252.8
|
|
|
7.1
|
%
|
$
|
1,170.1
|
|
||
|
•
|
2006 vs 2005
|
Margin
decreased by $20.8 million due to unfavorable weather, by $16.0 million
due to decreased off-system sales and by $6.5 million due to lower
industrial sales. These decreases were offset by residential and
commercial customer growth of $26.5 million. Purchased power cost
decreased due to lower volumes.
|
|
•
|
2005 vs 2004
|
Margin
increased by $41.4 million due to increased retail electric rates
that went into effect in January 2005, by $24.8 million due to residential
and commercial customer growth and by $16.4 million due to increased
off-system sales. These increases were offset by a $2.4 million decrease
due to unfavorable weather. Fuel used in generation increased $151.4
million due primarily to the increased cost of coal and natural gas
used
for electric generation. Purchased power cost decreased due to greater
availability of generation
facilities.
|
Megawatt
hour (MWh) sales volumes by class, related to the electric margin above, were
as
follows:
|
Classification
(in thousands)
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Residential
|
|
|
7,598
|
|
|
(0.5
|
)%
|
|
7,634
|
|
|
2.3
|
%
|
|
7,460
|
|
|
Commercial
|
|
|
7,249
|
|
|
1.9
|
%
|
|
7,117
|
|
|
3.1
|
%
|
|
6,900
|
|
|
Industrial
|
|
|
6,183
|
|
|
(6.0
|
)%
|
|
6,581
|
|
|
(2.9
|
)%
|
|
6,775
|
|
|
Sales
for resale (excluding interchange)
|
|
|
1,487
|
|
|
-
|
|
1,487
|
|
|
(2.5
|
)%
|
|
1,525
|
||
|
Other
|
|
|
531
|
|
|
0.8
|
%
|
|
527
|
|
|
0.2
|
%
|
|
526
|
|
|
Total
territorial
|
|
|
23,048
|
|
|
(1.3
|
)%
|
|
23,346
|
|
|
0.7
|
%
|
|
23,186
|
|
|
Negotiated
Market Sales Tariff (NMST)
|
|
|
1,475
|
|
|
(24.9
|
)%
|
|
1,963
|
|
|
6.4
|
%
|
|
1,845
|
|
|
Total
|
|
|
24,523
|
|
|
(3.1
|
)%
|
|
25,309
|
|
|
1.1
|
%
|
|
25,031
|
|
|
•
|
2006
vs 2005
|
Territorial
sales volumes decreased by 307 MWh due to lower industrial sales
volumes
and by 406 MWh due to unfavorable weather. These decreases were partially
offset by 408 MWh due to residential and commercial customer
growth.
|
|
•
|
2005
vs 2004
|
Territorial
sales volumes increased by 407 MWh primarily due to customer growth
partially offset by 261 MWh due to less favorable
weather.
|
Gas
Distribution
Gas
Distribution is comprised of the local distribution operations of SCE&G and
PSNC Energy. Gas distribution sales margins (including transactions with
affiliates) were as follows:
|
Millions
of dollars
|
|
2006
|
|
% Change
|
|
2005
|
|
% Change
|
|
2004
|
|
|||||
|
Operating
revenues
|
|
$
|
1,078.0
|
|
|
(7.8
|
)%
|
$
|
1,168.6
|
|
|
27.9
|
%
|
$
|
913.9
|
|
|
Less:
Gas purchased for resale
|
|
|
787.1
|
|
|
(12.0
|
)%
|
|
894.6
|
|
|
36.6
|
%
|
|
655.1
|
|
|
Margin
|
|
$
|
290.9
|
|
|
6.2
|
%
|
$
|
274.0
|
|
|
5.9
|
%
|
$
|
258.8
|
|
|
•
|
2006 vs 2005
|
Margin
increased by $17.5 million due to increased retail gas base rates
which
became effective with the first billing cycle in November 2005 and
by $4.0
million due to an SCPSC-approved increase in retail gas base rates
effective with the first billing cycle in November 2006. These increases
were offset by $4.0 million due to lower firm margin resulting from
customer conservation at SCE&G. The NCUC-approved rate increase at
PSNC Energy, effective with the first billing cycle in November 2006,
increased margin by $2.4 million, but was offset primarily by customer
conservation.
|
|
•
|
2005 vs 2004
|
Margin
increased primarily due to customer growth of $6.9 million at PSNC
Energy,
higher firm margin of $4.7 million at SCE&G and $4.6 million due to
increased retail gas base rates at SCE&G which became effective with
the first billing cycle in November 2005. These increases were offset
by a
$0.8 million decrease due to lower interruptible margin and transportation
revenue at SCE&G.
|
Dekatherm
(DT) sales volumes by class, including transportation gas, were as
follows:
|
Classification
(in thousands)
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
||||||||||
|
Residential
|
|
|
32,879
|
|
|
(13.2
|
)%
|
|
37,860
|
|
|
1.7
|
%
|
|
37,231
|
|
|
|
Commercial
|
|
|
25,718
|
|
|
(7.3
|
)%
|
|
27,750
|
|
|
1.8
|
%
|
|
27,271
|
|
|
|
Industrial
|
|
|
21,209
|
|
|
1.8
|
%
|
|
20,833
|
|
|
7.8
|
%
|
|
19,320
|
|
|
|
Transportation
gas
|
|
|
30,147
|
|
|
8.8
|
%
|
|
27,698
|
|
|
(1.8
|
)%
|
|
28,216
|
|
|
|
Sales
for resale
|
|
|
-
|
|
|
-
|
|
-
|
|
|
(100.0
|
)%
|
|
1
|
|
||
|
Total
|
|
|
109,953
|
|
|
(3.7
|
)%
|
|
114,141
|
|
|
1.9
|
%
|
|
112,039
|
|
|
|
•
|
2006 vs 2005
|
Residential
and commercial sales volumes decreased primarily due to milder weather
and
conservation. Transportation sales volumes increased primarily due
to
interruptible customers using gas instead of alternate
fuels.
|
|
•
|
2005 vs 2004
|
Commercial
and industrial sales volumes increased primarily due to more customers
buying commodity gas instead of purchasing alternate fuels and instead
of
transporting gas purchased from
others.
|
Gas
Transmission
Gas
Transmission is comprised of the operations of CGTC and, for periods prior
to
the name change and merger, SCPC and SCG Pipeline for all periods presented.
Gas
transmission transportation revenues and sales margins (including transactions
with affiliates) were as follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Transportation
revenue
|
$
|
26.5
|
40.2
|
%
|
$
|
18.9
|
6.2
|
%
|
$
|
17.8
|
||||||
|
Other
operating revenues
|
|
475.0
|
|
|
(26.5
|
)%
|
646.3
|
|
|
19.6
|
%
|
540.2
|
|
|||
|
Less:
Gas purchased for resale
|
|
|
439.2
|
|
|
(27.3
|
)%
|
|
604.2
|
|
|
21.6
|
%
|
|
496.9
|
|
|
Margin
|
|
$
|
62.3
|
|
|
2.1
|
%
|
$
|
61.0
|
|
|
(0.2
|
)%
|
$
|
61.1
|
|
|
•
|
2006
vs 2005
|
Margin
increased by $6.2 million due to increased transportation capacity
charges
(as a result of the merger discussed previously in the Overview section)
and by $1.4 million due to higher interruptible transportation revenues,
offset by $1.8 million due to decreased firm sales capacity charges
and by
$4.5 million due to lower industrial
margins.
|
|
•
|
2005
vs 2004
|
Operating
revenues and gas purchased for resale increased primarily due to
higher
commodity gas prices.
|
DT
sales
volumes by class, including transportation, were as follows:
|
Classification
(in thousands)
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Commercial
|
|
|
23
|
|
|
(57.4
|
)%
|
|
54
|
|
|
(52.2
|
)%
|
113
|
|
|
|
Industrial
|
|
|
18,875
|
|
|
(17.0
|
)
|
|
22,748
|
|
|
(20.5
|
)%
|
28,625
|
|
|
|
Transportation
|
|
|
57,546
|
|
|
27.7
|
|
45,055
|
|
|
18.3
|
%
|
38,078
|
|
||
|
Sales
for resale
|
|
|
33,327
|
|
|
(23.8
|
)
|
|
43,763
|
|
|
1.9
|
%
|
42,946
|
|
|
|
Total
|
|
|
109,771
|
|
|
(1.7
|
)
|
|
111,620
|
|
|
1.7
|
%
|
109,762
|
|
|
|
•
|
2006 vs 2005
|
Prior
to the merger on November 1, 2006, industrial volumes decreased primarily
due to higher commodity gas prices relative to alternate fuels. Subsequent
to the merger, CGTC operates as a transportation-only interstate
pipeline.
|
|
•
|
2005 vs 2004
|
Industrial
volumes decreased primarily due to higher commodity gas prices relative
to
alternate fuels.
|
Retail
Gas Marketing
Retail
Gas Marketing is comprised of SCANA Energy, which operates in Georgia’s natural
gas market. Retail Gas Marketing revenues and net income were as
follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Operating
revenues
|
|
$
|
608.1
|
|
|
(8.4
|
)%
|
$
|
664.0
|
|
|
20.3
|
%
|
$
|
552.0
|
|
|
Net
income
|
|
|
30.1
|
|
|
24.9
|
%
|
|
24.1
|
|
|
(16.9
|
)%
|
|
29.0
|
|
|
•
|
2006 vs 2005
|
Operating
revenues decreased primarily due to milder weather and customer
conservation, resulting in lower customer usage, which was partially
offset by higher average retail prices arising from higher commodity
gas
costs. Net income increased primarily due to decreased bad debt of
$9.0
million and lower operating and customer service expenses of $6.2
million,
partially offset by a margin decrease of $9.1 million, net of
taxes.
|
|
•
|
2005 vs 2004
|
Operating
revenues increased primarily as a result of higher average retail
prices
necessitated by higher commodity cost of gas. Net income decreased
primarily due to increased bad debt of $5.9 million, and operating,
marketing and customer service expenses of $4.4 million, offsetting
a
margin increase of $5.2 million, net of
taxes.
|
Delivered
volumes totaled 33.6 million DT in 2006 and 37.9 million DT in each of 2005
and 2004. Volumes declined in 2006 compared to 2005 and 2004 due to milder
weather and customer conservation.
Energy
Marketing
Energy
Marketing is comprised of the Company’s non-regulated marketing operations,
excluding SCANA Energy. Energy Marketing operating revenues and net loss were
as
follows:
|
Millions
of dollars
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
|||||||||
|
Operating
revenues
|
|
$
|
948.7
|
|
0.3
|
%
|
$
|
945.5
|
|
|
58.5
|
%
|
$
|
596.5
|
|
|
|
Net
loss
|
|
|
(0.4
|
)
|
|
(33.3)
|
%
|
|
(0.6
|
)
|
|
(70.0)
|
%
|
|
(2.0
|
)
|
|
•
|
2006 vs 2005
|
Operating
revenues increased due primarily to higher sales volume. Net loss
decreased due to lower operating expenses of $1.0 million which was
offset
by lower margin on sales of $0.9
million.
|
|
•
|
2005 vs 2004
|
Operating
revenues increased due to higher market prices and higher sales volume.
Net loss decreased primarily due to higher margins of $0.6 million
and
lower operating expenses of $0.8
million.
|
Delivered
volumes totaled 123.9 million DT in 2006, 101.0 million DT in 2005 and
91.8 million DT in 2004. Delivered volumes increased in 2006 compared
to 2005 primarily as a result of increased service to electric generation
facilities and municipalities in Georgia and South Carolina. Delivered
volumes increased in 2005 compared to 2004 primarily as a result of the
commencement of service to SCE&G’s Jasper County Electric Generating Station
in 2004.
Other
Operating Expenses
Other
operating expenses, which arose from the operating segments previously
discussed, were as follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Other
operation and maintenance
|
|
$
|
619.2
|
|
|
(2.0
|
)%
|
$
|
632.0
|
|
|
4.0
|
%
|
$
|
607.5
|
|
|
Depreciation
and amortization
|
|
|
332.4
|
|
|
(34.8
|
)%
|
|
509.9
|
|
|
92.3
|
%
|
|
265.1
|
|
|
Other
taxes
|
|
|
151.8
|
|
|
4.7
|
%
|
|
145.0
|
|
|
(0.4
|
)%
|
|
145.6
|
|
|
Total
|
|
$
|
1,103.4
|
|
|
(14.3
|
)%
|
$
|
1,286.9
|
|
|
26.4
|
%
|
$
|
1,018.2
|
|
|
•
|
2006 vs 2005
|
Other
operation and maintenance expenses decreased by $13.9 million due
to lower
bad debts and by $9.5 million due to lower operating and customer
service
expenses, both at retail gas marketing, and by $22.5 million due
to
decreased incentive compensation expense. These decreases were partially
offset by $11.1 million due to increased electric, generation,
transmission and distribution expenses, by $3.1 million due to increased
gas distribution expenses, by $3.6 million due to lower pension income
and
by $2.0 million due to higher customer service expenses at SCE&G.
Depreciation and amortization expense decreased by $185.8 million
due to
lower accelerated depreciation of the back-up dam at Lake Murray
in 2006
(see Income Taxes - Recognition
of Synthetic Fuel Tax Credits),
partially offset by $6.7 million due to property additions and higher
depreciation rates at SCE&G. Other taxes increased primarily due to
higher property taxes.
|
|
•
|
2005 vs 2004
|
Other
operation and maintenance expenses increased primarily due to increased
electric generation major maintenance expenses of $6.7 million, increased
expenses associated with the Jasper County Electric Generating Station
completed in May 2004 totaling $2.4 million, increased nuclear operating
and maintenance expenses of $2.4 million, higher expenses related
to
regulatory matters of $1.9 million and higher amortization of regulatory
assets of $3.6 million. The increases were offset primarily by decreased
long-term bonus and incentive plan expenses of $4.8 million and decreased
storm damage expenses of $0.9 million (at SCE&G). Depreciation and
amortization increased approximately $214.0 million due to accelerated
depreciation of the back-up dam at Lake Murray (see Income
Taxes
- Recognition
of Synthetic Fuel Tax Credits),
increased $6.5 million due to the completion of the Jasper County
Electric
Generating Station in May 2004 and increased $6.1 million due to
normal
net property changes at SCE&G. In addition, as a result of the January
2005 rate order, SCE&G received approval to amortize previously
deferred purchased power costs and to implement new depreciation
rates,
resulting in $17.3 million of additional depreciation and amortization
expense in the period.
|
Other
Income (Expense)
Other
income (expense) includes the results of certain incidental (non-utility)
activities and the activities of certain non-regulated subsidiaries. Components
of other income (expense), were as follows:
|
Millions
of dollars
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|||||||||||
|
Gain
(loss) on sale of investments
|
$
|
-
|
|
(100.0
|
)%
|
$
|
7.2
|
|
|
*
|
$
|
(21.2
|
)
|
|||
|
Gains
on sales of assets
|
3.4
|
|
100.0
|
%
|
|
1.7
|
|
|
*
|
|
0.7
|
|||||
|
Impairment
of investments
|
|
|
-
|
|
-
|
|
-
|
|
|
(100.0
|
)%
|
|
(26.9
|
)
|
||
|
Other
revenues
|
|
|
141.6
|
|
(42.9
|
)%
|
|
248.1
|
|
|
36.9
|
%
|
|
181.2
|
|
|
|
Other
expenses
|
|
|
(93.1
|
)
|
|
(53.5)
|
%
|
|
(200.3
|
)
|
|
25.3
|
%
|
|
(159.9
|
)
|
|
Total
|
|
$
|
51.9
|
|
(8.5
|
)%
|
$
|
56.7
|
|
|
*
|
$
|
(26.1
|
)
|
||
*
Greater
than 100%
|
•
|
2006 vs 2005
|
Other
revenues decreased $91.5 million due to lower power marketing activities,
$10.8 million due to the termination of a contract to operate a steam
combustion turbine at the United States Department of Energy (DOE)
Savannah River Site and by $4.3 million due to lower carrying costs
recognized on the unrecovered balance of the Lake Murray back-up
dam
project and lower management service fees of $10.0 million received
by
Primesouth, Inc., as discussed at Income Taxes
- Recognition
of Synthetic Fuel Tax Credits
below. These decreases were partially offset by higher interest income
of
$9.4 million and higher third-party coal sales revenue of $4.8
million.
Other
expenses decreased by $90.6 million due to lower power marketing
activities and $4.4 million due to the termination of the DOE’s Savannah
River Site contract. These decreases were partially offset by increased
charges of $8.7 million related to the settlement of the FERC power
marketing matter (see Note 10 to the consolidated financial statements)
and higher expenses to support third-party coal sales of $3.6
million.
|
|
•
|
2005 vs 2004
|
Gain
(loss) on sale of investments increased due to the receipt in 2005
of
additional proceeds of $6.0 million from the 2003 sale of the Company’s
investment in ITC Holding. These proceeds had been held in escrow
pending
resolution of certain contingencies. In 2004 the Company recognized
a
$21.0 million loss on the sale of investments in Knology and
ITC^DeltaCom. In 2004 impairments of $26.9 million were recorded
on
investments in Knology, ITC Holding and Magnolia Holding.
Other
revenues increased $42.8 million due to higher power marketing activity
and $10.9 million due to carrying costs recognized on the unrecovered
balance of the Lake Murray back-up dam project.
Other
expenses increased $43.1 million due to higher power marketing activity
and $.8 million due to the charge associated with the FERC power
marketing
matter. (See Note 10 to the consolidated financial
statements.)
|
Interest
Expense
Components
of interest expense, net of the debt component of AFC, were as
follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||
|
Interest
on long-term debt, net
|
|
$
|
190.9
|
|
|
(4.3
|
)%
|
$
|
199.5
|
|
|
0.7
|
%
|
$
|
198.1
|
|
|
Other
interest expense
|
|
|
18.7
|
|
|
48.4
|
%
|
|
12.6
|
|
|
*
|
|
4.3
|
|
|
|
Total
|
|
$
|
209.6
|
|
|
(1.2
|
)%
|
$
|
212.1
|
|
|
4.8
|
%
|
$
|
202.4
|
|
*
Greater
than 100%
|
•
|
2006 vs 2005
|
Interest
on long-term debt decreased primarily due to reduced long-term borrowings,
partially offset by increased variable rates. Other interest expense
increased primarily due to increased short-term
borrowings.
|
|
•
|
2005 vs 2004
|
Interest
on long-term debt increased primarily due to the lower level of AFC
resulting from reductions in the levels of capital expenditures subsequent
to the completion of the Jasper County Electric Generation Station
in May
2004 and the Lake Murray back-up dam project in May 2005, partially
offset
by the redemption of outstanding debt in late 2004. Other interest
expense
increased primarily due to increased short-term borrowings at
SCE&G.
|
Income
Taxes
Income
taxes, exclusive of amounts related to the cumulative effect of an accounting
change, increased in 2006 compared to 2005 by $237.6 million and decreased
in 2005 compared to 2004 by $240.8 million. Changes in income taxes are
primarily due to changes in operating income and other income, although in
2005
the benefits of synthetic fuel credits of $179.0 million were also recognized
pursuant to the January 2005 electric rate order. The Company’s effective tax
rate has been favorably impacted in recent years by the flow-through of state
investment tax credits and the equity portion of AFC.
Recognition
of Synthetic Fuel Tax Credits
SCE&G
holds equity-method investments in two partnerships involved in converting
coal
to synthetic fuel, the use of which fuel qualifies for federal income tax
credits. Under an accounting plan approved by the Public Service Commission
of
South Carolina (SCPSC) in June 2000, the synthetic fuel tax credits generated
by
the partnerships and passed through to SCE&G, net of partnership losses and
other expenses, were deferred until the SCPSC approved its application to offset
capital costs of the Lake Murray back-up dam project. Under the accounting
methodology approved by the SCPSC in a January 2005 order, construction costs
related to the project were recorded in utility plant in service in a special
dam remediation account outside of rate base, and depreciation is being
recognized against the balance in this account on an accelerated basis, subject
to the availability of the synthetic fuel tax credits.
The
level
of depreciation expense and related tax benefit recognized in the income
statement is equal to the available synthetic fuel tax credits, less partnership
losses and other expenses, net of taxes. As a result, the balance of unrecovered
costs in the dam remediation account declines as accelerated depreciation is
recorded. Although these entries collectively have no impact on consolidated
net
income, they have a significant impact on individual line items within the
income statement. The
accelerated depreciation, synthetic fuel tax credits, partnership losses and
the
income tax benefit arising from such losses recognized by SCE&G during 2006
and 2005 are as follows:
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
|
|
|
|
|
|
||
|
Depreciation
and amortization expense
|
|
$
|
(28.2
|
)
|
$
|
(214.0
|
)
|
|
|
|
|
|
|
|
||
|
Income
tax benefits:
|
|
|
|
|
|
|
|
|
From synthetic fuel tax credits
|
|
|
30.0
|
|
179.0
|
|
|
|
From accelerated depreciation
|
|
|
10.8
|
|
81.8
|
|
|
|
From partnership losses
|
|
|
7.8
|
|
28.9
|
|
|
|
Total
income tax benefits
|
|
|
48.6
|
|
289.7
|
|
|
|
|
|
|
|
|
|
||
|
Losses
from Equity Method Investments
|
|
|
(20.4
|
)
|
|
(75.7
|
)
|
|
|
|
|
|
|
|
||
|
Impact
on Net Income
|
|
|
-
|
|
-
|
|
|
The
2005
amounts above reflect the recognition of previously deferred tax credits, while
the 2006 amounts reflect the likelihood that credits available in 2006 will
be
phased down pursuant to regulations which limit the credits based on the
relative commodity price of crude oil.
Depreciation
on the Lake Murray back-up dam project account will be matched to available
synthetic fuel tax credits on a quarterly basis until the balance in the dam
remediation account is zero or until all of the available synthetic fuel tax
credits have been utilized. The synthetic fuel tax credit program expires at
the
end of 2007.
The
availability of the synthetic fuel tax credits is dependent on several factors,
one of which is the average annual domestic wellhead price per barrel of crude
oil as published by the U.S. Government. Under a phase-out provision included
in
the program, if the domestic wellhead reference price of oil per barrel for
a
given year is below an inflation-adjusted benchmark range for that year, all
of
the synthetic fuel tax credits that have been generated in that year would
be
available for use. If that price is above the benchmark range, none of the
tax
credits would be available. If that price falls within the benchmark range,
a
calculated portion of the credits would be available.
The
benchmark price range for 2005, published in April 2006, was $53 to $67 per
barrel, and no phase-out applied. However, SCE&G’s analysis indicates that
the available synthetic fuel tax credits for 2006 are likely to be impacted
by
the phase-out calculation. As such, in 2006 the Company recorded synthetic
fuel
tax credits and applied those credits to allow the recording of accelerated
depreciation related to the balance in the dam remediation project account
based
on an estimate that only 67% of credits generated will be available (phase-out
of 33%). The Company cannot predict what impact, if any, the price of oil may
have on the Company’s ability to earn and utilize synthetic fuel tax credits in
the future. However, there is significant uncertainty as to the continued
availability of the credits in 2007. The availability of these synthetic fuel
tax credits is also subject to coal availability and other operational risks
related to the generating plants.
The
Company does not expect available credits to be sufficient to fully recover
the
construction costs of dam remediation, and total unrecovered cost at the end
of
December 31, 2007 may be significant. To the extent that available credits
are
not sufficient to fully recover the construction costs of the dam remediation,
regulatory action to allow recovery of those remaining costs may be sought.
As
of December 31, 2006, remaining unrecovered costs, based on management’s
recording of accelerated depreciation and related tax benefits, were $69.1
million.
Finally,
Primesouth, Inc., a subsidiary of SCANA, provides management and maintenance
services for a non-affiliated synthetic fuel production facility. Reduced
synthetic fuel tax credit availability under the above phase-out provisions
also
adversely impacts the level of payment Primesouth receives for these services.
The fees recognized by Primesouth in 2006 were $10.0 million lower than amounts
recognized in 2005.
Cash
requirements for SCANA’s regulated subsidiaries arise primarily from their
operational needs, funding their construction programs and payment of dividends
to SCANA. The ability of the regulated subsidiaries to replace existing plant
investment, to expand to meet future demand for electricity and gas and to
install equipment necessary to comply with environmental regulations, will
depend on their ability to attract the necessary financial capital on reasonable
terms. Regulated subsidiaries recover the costs of providing services through
rates charged to customers. Rates for regulated services are generally based
on
historical costs. As customer growth and inflation occur and these subsidiaries
continue their ongoing construction programs, rate increases will be sought.
The
future financial position and results of operations of the regulated
subsidiaries will be affected by their ability to obtain adequate and timely
rate and other regulatory relief, if requested.
SCE&G
expects to require the addition of base load electrical generation by 2015
and
is evaluating alternatives, including fossil and nuclear-fueled generation
facilities. In February 2006, SCE&G and the South Carolina Public Service
Authority (Santee Cooper), a state-owned utility in South Carolina (joint owners
of V. C. Summer Nuclear Station (Summer Station)), announced their selection
of
the Summer Station site as the preferred site for new nuclear generation
facilities should such generation be considered the best alternative in the
future. Due to the significant lead time required for construction of nuclear
generation facilities, the joint owners are preparing an application to the
United States Nuclear Regulatory Commission (NRC) for a combined construction
and operating license (COL) that would cover two nuclear units. The COL
application, which is expected to be completed and filed in 2007, would be
reviewed by the NRC for an estimated three years. Issuance of a COL would not
obligate the joint owners to build nuclear generation facilities. The final
decision to build nuclear generation facilities will be influenced by several
factors, including NRC licensing attainment, estimates of construction and
operating costs, the cost of competing fuels, regulatory and environmental
requirements and financial market conditions.
The
Company’s leverage ratio of debt to capital was 55% at December 31, 2006.
If the agencies rating the Company’s credit determine that the Company’s
leverage ratio, among other measures, is too high, these rating agencies may
downgrade the Company’s debt. Such a downgrade would adversely affect the
interest rate the Company is able to obtain when issuing debt, both short-term
and long-term, and would limit the Company’s access to capital markets.
The
Company’s current estimates of its capital expenditures for construction and
nuclear fuel for 2007-2009, which are subject to continuing review and
adjustment, are as follows:
Estimated
Capital Expenditures
|
Millions
of dollars
|
|
2007
|
2008
|
2009
|
|
|||||
|
SCE&G:
|
|
|
|
|
|
|
|
|||
|
Electric
Plant:
|
|
|
|
|
|
|
|
|||
|
Generation (including GENCO)
|
|
$
|
220
|
|
$
|
361
|
$
|
255
|
|
|
|
Transmission
|
|
|
45
|
|
|
52
|
|
35
|
|
|
|
Distribution
|
|
|
151
|
|
|
155
|
|
153
|
|
|
|
Other
|
|
|
28
|
|
|
38
|
|
17
|
|
|
|
Nuclear Fuel
|
|
|
55
|
|
|
6
|
|
26
|
|
|
|
Gas
|
|
|
50
|
|
|
59
|
|
52
|
|
|
|
Common
and other
|
|
|
28
|
|
|
10
|
|
12
|
|
|
|
Total
SCE&G
|
|
|
577
|
|
|
681
|
|
550
|
|
|
|
Other
Companies Combined
|
|
|
151
|
|
|
160
|
|
142
|
|
|
|
Total
|
|
$
|
728
|
|
$
|
841
|
$
|
692
|
|
|
The
Company’s contractual cash obligations as of December 31, 2006 are
summarized as follows:
Contractual
Cash Obligations
|
Millions
of dollars
|
|
Total
|
Less
than
1
year
|
1-3 years
|
4-5 years
|
After
5 years
|
|
|||||||||
|
Long-term
and short-term debt (including
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
interest
and preferred stock)
|
|
$
|
6,310
|
|
$
|
841
|
|
$
|
900
|
|
$
|
1,151
|
|
$
|
3,418
|
|
|
Capital
leases
|
|
|
2
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
Operating
leases
|
|
|
57
|
|
|
30
|
|
|
25
|
|
|
-
|
|
|
2
|
|
|
Purchase
obligations
|
|
|
647
|
|
|
348
|
|
296
|
|
|
2
|
|
|
1
|
|
|
|
Other
commercial commitments
|
|
|
7,513
|
|
|
1,275
|
|
|
2,283
|
|
|
977
|
|
|
2,978
|
|
|
Total
|
|
$
|
14,529
|
|
$
|
2,495
|
|
$
|
3,505
|
|
$
|
2,130
|
|
$
|
6,399
|
|
Included
in other commercial commitments are estimated obligations under forward
contracts for natural gas purchases. Forward contracts for natural gas purchases
include customary “make-whole” or default provisions, but are not considered to
be “take-or-pay” contracts. Certain of these contracts relate to regulated
businesses; therefore, the effects of such contracts on fuel costs are reflected
in electric or gas rates. Also included in other commercial commitments is
a
“take-and-pay” contract for natural gas which expires in 2019 and estimated
obligations for coal and nuclear fuel purchases. See Note 10 to the
consolidated financial statements.
Included
in purchase obligations are customary purchase orders under which the Company
has the option to utilize certain vendors without the obligation to do so.
The
Company may terminate such obligations without penalty.
In
addition to the contractual cash obligations above, the Company sponsors a
noncontributory defined benefit pension plan and an unfunded health care and
life insurance benefit plan for retirees. The pension plan is adequately funded,
and no further contributions are anticipated until after 2010. Cash payments
under the health care and life insurance benefit plan were $9.7 million in
2006, and such annual payments are expected to increase to the
$13-$14 million range in the future.
In
addition, the Company is party to certain New York Mercantile Exchange (NYMEX)
futures contracts for which any unfavorable market movements are funded in
cash.
These derivatives are accounted for as cash flow hedges under SFAS 133,
“Accounting
for Derivative Instruments and Hedging Activities,”
as
amended, and their effects are reflected within other comprehensive income
until
the anticipated sales transactions occur. See further discussion at Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
The
Company also has a legal obligation associated with the decommissioning and
dismantling of Summer Station and other conditional asset retirement obligations
that are not listed in the contractual cash obligations table. See Notes 1B
and 10H to the consolidated financial statements.
The
Company anticipates that its contractual cash obligations will be met through
internally generated funds and the incurrence of additional short-term and
long-term indebtedness. The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements for the foreseeable
future.
Cash
outlays for 2006 (actual) and 2007 (estimated) for certain expenditures are
as
follows:
|
Millions
of dollars
|
|
2006
|
2007
|
|
|||
|
Property
additions and construction expenditures, net of AFC
|
|
$
|
527
|
|
$
|
673
|
|
|
Nuclear
fuel expenditures
|
|
|
17
|
|
|
55
|
|
|
Investments
|
|
|
25
|
|
|
19
|
|
|
Total
|
|
$
|
569
|
|
$
|
747
|
|
Financing
Limits and Related Matters
The
Company’s issuance of various securities, including long-term and short-term
debt, is subject to customary approval or authorization by regulatory bodies
including state public service commissions and FERC. Descriptions of financing
programs currently utilized by the Company follow.
Pursuant
to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC
authority to issue short-term debt. Effective February 8, 2006 the FERC has
authorized SCE&G and GENCO to issue up to $700 million and $100 million,
respectively, of unsecured promissory notes or commercial paper with maturity
dates of one year or less. This authorization expires February 7,
2008.
At
December 31, 2006, SCANA, SCE&G (including Fuel Company) and PSNC
Energy had available the following lines of credit and short-term borrowings
outstanding:
|
Millions
of dollars
|
|
SCANA
|
SCE&G
|
PSNC Energy
|
|
|||||
|
Lines
of credit (total and unused):
|
|
|
|
|
|
|
|
|||
|
Committed long-term (expires December 2011)
|
|
$
|
200
|
$
|
650
|
$
|
250
|
|||
|
Uncommitted
|
|
|
103
|
(a)
|
|
-
|
|
-
|
||
|
Short-term
borrowings outstanding:
|
|
|
|
|
||||||
|
Bank loans/commercial paper (270 or fewer days)
|
|
$
|
-
|
$
|
362.2
|
$
|
124.7
|
|||
|
Weighted
average interest rate
|
|
|
-
|
5.38
|
%
|
5.40
|
%
|
|||
(a)
SCANA
or SCE&G may use $78 million of these lines of credit.
SCANA
Corporation
SCANA
has
in effect a medium-term note program for the issuance from time to time of
unsecured medium-term debt securities. The Indenture under which they are issued
contains no specific limit on the amount which may be issued.
South
Carolina Electric & Gas Company
In
September 2006 SCE&G discharged its bond indenture dated January 1,
1945 which covered substantially all of its properties. SCE&G remains
subject to a bond indenture dated April 1, 1993 (Mortgage) covering
substantially all of its electric properties under which all of its currently
outstanding First Mortgage Bonds and all of its future mortgage-backed debt
(Bonds) has been and will be issued. Bonds may be issued under the Mortgage
in
an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded
Net
Property Additions (as therein defined), (2) the aggregate principal amount
of
retired Bonds and (3) cash deposited with the trustee. Bonds will be issuable
under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12
consecutive months out of the 18 months immediately preceding the month of
issuance are at least twice the annual interest requirements on all outstanding
Bonds and Bonds to be outstanding (Bond Ratio). For the year ended
December 31, 2006, the Bond Ratio was 6.99.
SCE&G’s
Restated Articles of Incorporation (Articles) prohibit issuance of additional
shares of preferred stock without the consent of the preferred shareholders
unless net earnings (as therein defined) for the 12 consecutive months
immediately preceding the month of issuance are at least one and one-half times
the aggregate of all interest charges and preferred stock dividend requirements
on all shares of preferred stock outstanding immediately after the proposed
issue (Preferred Stock Ratio). For the year ended December 31, 2006, the
Preferred Stock Ratio was 1.99.
The
Articles also require the consent of a majority of the total voting power of
SCE&G’s preferred stock before SCE&G may issue or assume any unsecured
indebtedness if, after such issue or assumption, the total principal amount
of
all such unsecured indebtedness would exceed ten percent of the aggregate
principal amount of all of SCE&G’s secured indebtedness and capital and
surplus (the ten percent test). No such consent is required to enter into
agreements for payment of principal, interest and premium for securities issued
for pollution control purposes. At December 31, 2006, the ten percent test
would have limited total issuances of unsecured indebtedness to approximately
$428.4 million. Unsecured indebtedness at December 31, 2006, totaled
approximately $357.8 million, and was comprised primarily of short-term
borrowings.
Financing
Cash Flows
During
2006 the Company experienced net cash outflows related to financing activities
of $83 million primarily due to the payment of dividends, which were partially
offset by net increases in long-term and short-term borrowings and proceeds
from
common stock issuances.
The
Company uses interest rate swap agreements to manage interest rate risk. These
swap agreements provide for the Company to pay variable and receive fixed rate
interest payments and are designated as fair value hedges of certain debt
instruments. The Company may terminate a swap agreement and may replace it
with
a new swap also designated as a fair value hedge. Payments received upon
termination of such swaps are recorded as basis adjustments to long-term debt
and are amortized as reductions to interest expense over the term of the
underlying debt. At December 31, 2006, the estimated fair value of the
Company’s swaps totaled a $0.1 million gain related to combined notional
amounts of $44.2 million.
In
anticipation of the issuance of debt, the Company may use interest rate lock
or
similar agreements to manage interest rate risk. Payments received or made
upon
termination of such agreements are recorded within long-term debt on the balance
sheet and are amortized to interest expense over the term of the underlying
debt. In connection with the issuance of first mortgage bonds in June 2006,
SCE&G received approximately $8.8 million upon the termination of an
interest rate lock. These proceeds are being amortized over the life of the
related debt, thereby reducing its effective interest rate. As permitted by
SFAS
104 “Statement
of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and
Classification of Cash Flows from Hedging Transactions,” these
proceeds have been classified as a financing activity in the consolidated
statement of cash flows.
For
additional information on significant financing activities, see Note 4 to
the consolidated financial statements.
On
February 15, 2007, SCANA increased the quarterly cash dividend rate on
SCANA common stock to $.44 per share, an increase of 4.8%. The new dividend
is
payable April 1, 2007 to stockholders of record on March 9,
2007.
Capital
Expenditures
For
the
three years ended December 31, 2006, the Company’s capital expenditures for
environmental control totaled $160.2 million. These expenditures were in
addition to expenditures included in “Other operation and maintenance” expenses,
which were $28.7 million, $25.2 million, and $21.5 million during
2006, 2005 and 2004, respectively. It is not possible to estimate all future
costs related to environmental matters, but forecasts for capitalized
environmental expenditures for the Company are $154.7 million for 2007 and
$494.8 million for the four-year period 2008 through 2011. These expenditures
are included in the Company’s Estimated Capital Expenditures table, discussed in
Liquidity and Capital Resources, and include the matters discussed
below.
Electric
Operations
In
March
2005, the United States Environmental Protection Agency (EPA) issued a final
rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District
of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide
and sulfur dioxide emissions in order to attain mandated state levels. SCE&G
has petitioned the United States Court of Appeals for the District of Columbia
Circuit to review CAIR. Several other electric utilities have filed separate
petitions. The petitioners seek a change in the method CAIR uses to allocate
sulfur dioxide emission allowances to a method the petitioners believe is more
equitable. The Company believes that installation of additional air quality
controls will be needed to meet the CAIR requirements. The Company is reviewing
the final rule. Compliance plans and cost to comply with the rule will be
determined once the Company completes its review. Such costs will be material
and are expected to be recoverable through rates.
In
March
2005, the EPA issued a final rule establishing a mercury emissions cap and
trade
program for coal-fired power plants that requires limits to be met in two
phases, in 2010 and 2018. Although
the Company expects to be able to meet the Phase I limits through those measures
it already will be taking to meet its CAIR obligations, it is uncertain as
to
how the Phase II limits will be met. Assuming Phase II limits remain unchanged,
installation of additional air quality controls likely will be required to
comply with the rule’s Phase II mercury emission caps. Final compliance plans
and costs to comply with the rule are still under review. Such costs will be
material and are expected to be recoverable through rates.
The
EPA
has undertaken an aggressive enforcement initiative against the utilities
industry, and the United States Department of Justice (DOJ) has brought suit
against a number of utilities in federal court alleging violations of the Clean
Air Act (CAA). At least two of these suits have either been tried or have had
substantive motions decided—one favorable to the industry and one not. The one
not favorable to the industry is not binding as precedent and the one favorable
to the industry likely is precedent and is consistent with current Company
interpretation of the law and its resulting maintenance practices. Prior to
the
suits, those utilities had received requests for information under
Section 114 of the CAA and were issued Notices of Violation. The basis for
these suits is the assertion by the EPA, under a stringent rule known as New
Source Review (NSR), that maintenance activities undertaken by the utilities
over the past 20 or more years constitute “major modifications” which would have
required the installation of costly Best Available Control Technology (BACT).
SCE&G and GENCO have received and responded to Section 114 requests for
information related to Canadys, Wateree and Williams Stations. The regulations
under the CAA provide certain exemptions to the definition of “major
modifications,” including an exemption for routine repair, replacement or
maintenance. On October 27, 2003, EPA published a final revised NSR rule in
the Federal Register with an effective date of December 26, 2003. The rule
represents an industry-favorable departure from certain positions advanced
by
the federal government in the NSR enforcement initiative. However, on motion
of
several Northeastern states, the United States Circuit Court of Appeals for
the
District of Columbia stayed the effect of the final rule. The ultimate
application of the final rule to the Company is uncertain. The Company has
analyzed each of the activities covered by the EPA’s requests and believes each
of these activities is covered by the exemption for routine repair, replacement
and maintenance under what it believes is a fair reading of both the prior
regulation and the contested revised regulation. The regulations also provide
an
exemption for an increase in emissions resulting from increased hours of
operation or production rate and from demand growth.
The
current state of continued DOJ enforcement actions is the subject of
industry-wide speculation, but it is possible that the EPA will commence
enforcement actions against SCE&G and GENCO, and the EPA has the authority
to seek penalties at the rate of up to $27,500 per day for each violation.
The
EPA also could seek installation of BACT (or equivalent) at the three plants.
The Company believes that any enforcement actions relative to the Company’s
compliance with the CAA would be without merit. The Company has completed
installation of selective catalytic reactors at Wateree and Williams for
nitrogen oxides control and is proceeding with plans to install sulfur dioxide
scrubbers at both of these stations to meet CAIR regulations. These actions
would mitigate many of the concerns with NSR. SCE&G and GENCO expect to
incur capital expenditures totaling approximately $450 million over the
2007-2010 period to install this new equipment. SCE&G and GENCO expect to
have increased operation and maintenance costs of approximately $4 million
in
2010 and $27 million in 2011 and each subsequent year thereafter. To meet
compliance requirements for the years 2012 through 2016, the Company anticipates
additional capital expenditures totaling approximately
$480 million.
The
Clean
Water Act, as amended, provides for the imposition of effluent limitations
that
require treatment for wastewater discharges. Under the Clean Water Act,
compliance with applicable limitations is achieved under a national permit
program. Discharge permits have been issued for all, and renewed for nearly
all,
of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these
permits, the permitting agency has implemented a more rigorous program of
monitoring and controlling discharges, has modified the requirements for cooling
water intake structures, and has required strategies for toxicity reduction
in
wastewater streams. The Company is conducting studies and is developing or
implementing compliance plans for these initiatives. Congress is expected to
consider further amendments to the Clean Water Act. Such legislation may include
limitations to mixing zones and toxicity-based standards. These provisions,
if
passed, could have a material adverse impact on the financial condition, results
of operations and cash flows of the Company, SCE&G and GENCO.
The
Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) required that the United
States government, by January 31, 1998, accept and permanently dispose of
high-level radioactive waste and spent nuclear fuel. The Nuclear Waste Act
also
imposed on utilities the primary responsibility for storage of their spent
nuclear fuel until the repository is available. SCE&G entered into a
Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste (Standard Contract) with the DOE in 1983 providing for
permanent disposal of its spent nuclear fuel in exchange for agreed payments
fixed in the Standard Contract at particular amounts. On January 28, 2004,
SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in
the Court of Federal Claims against the DOE for breach of the Standard Contract,
because as of the date of filing, the federal government had accepted no spent
fuel from Summer Station or any other utility for transport and disposal, and
has indicated that it does not anticipate doing so until 2010, at the earliest.
As a consequence of the federal government’s breach of contract, the plaintiffs
have incurred and will continue to incur substantial costs. On January 9, 2006,
SCE&G and Santee Cooper accepted a $9 million settlement from DOE. The
payment reimbursed the plaintiffs for certain costs incurred from January 31,
1998 through July 31, 2005. SCE&G recorded its portion ($6 million) of the
settlement as a reduction to its fuel costs. As a result, most of the credit
was
passed through to its customers through the fuel clause component of its retail
electric rates. The settlement also provides for the plaintiffs to submit an
annual application to DOE for the reimbursement of certain costs incurred
subsequent to July 31, 2005. SCE&G has on-site spent nuclear fuel storage
capability until at least 2018 and expects to be able to expand its storage
capacity to accommodate the spent nuclear fuel output for the life of the plant
through dry cask storage or other technology as it becomes
available.
SCE&G
has been named, along with 53 others, by the EPA as a PRP at the Alternate
Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.
The EPA placed the site on the National Priorities List on April 19, 2006.
AER
conducted hazardous waste storage and treatment operations from 1975 to 2000,
when the site was abandoned. While operational, AER processed fuels from
waste oils, treated industrial coolants and oil/water emulsions, recycled
solvents and blended hazardous waste fuels. During that time, SCE&G
occasionally used AER for the processing of waste solvents, oily rags and oily
wastewater. EPA and the State of Georgia have documented that a release or
releases have occurred at the site leading to contamination of groundwater,
surface water and soils. EPA and the State of Georgia have conducted a
preliminary assessment and site inspection. The site has not been cleaned up
nor
has a cleanup cost been estimated. Although a basis for the allocation of
clean-up costs among the PRPs is unclear, SCE&G does not believe that its
involvement at this site would result in an allocation of costs that would
have
a material adverse impact on its results of operations, cash flows or financial
condition. Any cost allocated to SCE&G arising from the remediation of this
site, net of insurance recoveries, if any, is expected to be recoverable through
rates.
SCE&G
has been named, along with 29 others, by the EPA as a potentially responsible
party (PRP) at the Carolina Transformer Superfund site located in Fayetteville,
North Carolina. The Carolina Transformer Company (CTC) conducted an
electrical transformer rebuilding and repair operation at the site from 1967
to
1984. During that time, SCE&G occasionally used CTC for the repair of
existing transformers, purchase of new transformers and sale of used
transformers. In 1984, EPA initiated a cleanup of PCB-contaminated soil
and groundwater at the site. EPA reports that it has spent $36 million to
date. Although a basis for the allocation of clean-up costs among the
PRPs is unclear, SCE&G does not believe that its involvement at this site
would result in an allocation of costs that would have a material adverse impact
on its results of operations, cash flows or financial condition. Any cost
allocated to SCE&G arising from the remediation of this site, net of
insurance recoveries, if any, is expected to be recoverable through
rates.
Gas
Distribution
The
Company maintains an environmental assessment program to identify and evaluate
current and former operations sites that could require environmental cleanup.
As
site assessments are initiated, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures may differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates.
Deferred
amounts for SCE&G, net of amounts previously recovered through rates and
insurance settlements, totaled $17.9 million at December 31, 2006 and
$17.7 million at December 31, 2005. The deferral includes the estimated
costs associated with the following matters.
SCE&G
owns a decommissioned MGP site in the Calhoun Park area of Charleston, South
Carolina. SCE&G anticipates that remediation for contamination at the site
will be completed in late 2007, with certain monitoring and retreatment
activities continuing until 2011. As of December 31, 2006, SCE&G has
spent $22.3 million to remediate the Calhoun Park site, and expects to spend
an
additional $1.1 million. In addition, the National Park Service of the
Department of the Interior made an initial demand to SCE&G for payment of
$9.1 million for certain costs and damages relating to this site. SCE&G
expects to recover any cost arising from the remediation of this site through
rates.
SCE&G
owns three other decommissioned MGP sites in South Carolina which contain
residues of by-product chemicals. One of the sites has been remediated and
will
undergo routine monitoring until released by DHEC. The other sites are currently
being investigated under work plans approved by DHEC. SCE&G anticipates that
major remediation activities for the three sites will be completed in 2011.
As
of December 31, 2006, SCE&G has spent $4.8 million related to
these three sites, and expects to spend an additional $11.2 million. SCE&G
expects to recover any cost arising from the remediation of these sites through
rates.
PSNC
Energy is responsible for environmental cleanup at five sites in North Carolina
on which MGP residuals are present or suspected. PSNC Energy’s remediation costs
for these sites will depend on a number of factors, such as actual site
conditions, third-party claims and recoveries from other PRPs. PSNC Energy
has
recorded a liability and associated regulatory asset of $6.9 million, which
reflects its estimated remaining liability at December 31, 2006. Amounts
incurred and deferred to date, net of insurance settlements, that are not
currently being recovered through gas rates are $0.9 million. PSNC Energy
expects to recover any costs allocated to PSNC Energy arising from the
remediation of these sites through gas rates.
Material
retail rate proceedings are described in more detail in Note 2 to the
consolidated financial statements.
South
Carolina Electric & Gas Company
SCE&G
is subject to the jurisdiction of the SCPSC as to retail electric and gas rates,
service, accounting, issuance of securities (other than short-term borrowings)
and other matters.
The
Natural Gas Stabilization Act of 2005 allows natural gas distribution companies
to request annual adjustments to rates to reflect changes in revenues and
expenses and changes in investment. Such annual adjustments are subject to
certain qualifying criteria and review by the SCPSC.
Public
Service Company of North Carolina, Incorporated
PSNC
Energy is subject to the jurisdiction of the NCUC as to gas rates, issuance
of
securities (other than notes with a maturity of two years or less or renewals
of
notes with a maturity of six years or less), accounting and other matters.
The
United States Congress passed the Pipeline Safety Improvement Act of 2002 (the
Pipeline Safety Act), directing the United States Department of Transportation
(DOT) to establish the Integrity Management Rule for operations of natural
gas
systems with transmission pipelines located near moderate to high density
populations. Of PSNC Energy’s approximately 720 miles of transmission pipeline
subject to the Pipeline Safety Act, approximately 110 miles are located within
these areas. Fifty percent of these miles of pipeline must be assessed by
December 2007, and the remainder by December 2012. Depending on the
assessment method used, PSNC Energy will be required to reinspect these same
miles of pipeline every five to seven years. Though cost estimates for this
project were developed using various assumptions, each of which is subject
to
imprecision, PSNC Energy currently estimates the total cost through December
2012 to be $8 million for the initial assessments, not including any
subsequent remediation that may be required. Effective November 1, 2004 the
NCUC authorized deferral accounting for certain expenses incurred to comply
with
DOT’s pipeline integrity management requirements. In accordance with an October
2006 NCUC rate order, $1.4 million in costs incurred and deferred through June
30, 2006 are now being recovered through rates over a three-year period.
Additionally, management believes that all subsequent costs will be recoverable
by PSNC Energy through rates.
Carolina
Gas Transmission Corporation
CGTC
has
approximately 65 miles of transmission line that are covered by the Integrity
Management Rule of the Pipeline Safety Act. Though cost estimates for this
project were developed using various assumptions, each of which is subject
to
imprecision, CGTC currently estimates the total cost to be $10.9 million
for the initial assessments and any subsequent remediation required through
December 2012.
Following
are descriptions of the Company’s accounting policies and estimates which are
most critical in terms of reporting financial condition or results of
operations.
Utility
Regulation
SCANA’s
regulated utilities are subject to the provisions of SFAS 71, “Accounting
for the Effects of Certain Types of Regulation,”
which
require them to record certain assets and liabilities that defer the recognition
of expenses and revenues to future periods as a result of being rate-regulated.
In the future, as a result of deregulation or other changes in the regulatory
environment, the Company may no longer meet the criteria for continued
application of SFAS 71 and could be required to write off its regulatory
assets and liabilities. Such an event could have a material adverse effect
on
the results of operations, liquidity or financial position of the Company’s
Electric Distribution and Gas Distribution segments in the period the write-off
would be recorded. See Note 1 to the consolidated financial statements for
a description of the Company’s regulatory assets and liabilities, including
those associated with the Company’s environmental assessment
program.
The
Company’s generation assets would be exposed to considerable financial risks in
a deregulated electric market. If market prices for electric generation do
not
produce adequate revenue streams and the enabling legislation or regulatory
actions do not provide for recovery of the resulting stranded costs, the Company
could be required to write down its investment in those assets. The Company
cannot predict whether any write-downs will be necessary and, if they are,
the
extent to which they would adversely affect the Company’s results of operations
in the period in which they would be recorded. As of December 31, 2006, the
Company’s net investments in fossil/hydro and nuclear generation assets were
approximately $2.3 billion and $506 million, respectively.
Revenue
Recognition and Unbilled Revenues
Revenues
related to the sale of energy are recorded when service is rendered or when
energy is delivered to customers. Because customers of the Company’s utilities
and retail gas operations are billed on cycles which vary based on the timing
of
the actual reading of their electric and gas meters, the Company records
estimates for unbilled revenues at the end of each reporting period. Such
unbilled revenue amounts reflect estimates of the amount of energy delivered
to
customers since the date of the last reading of their meters. Such unbilled
revenues reflect consideration of estimated usage by customer class, the effects
of different rate schedules, changes in weather and, where applicable, the
impact of weather normalization provisions of rate structures. The accrual
of
unbilled revenues in this manner properly matches revenues and related costs.
Accounts receivable included unbilled revenues of $177.6 million at
December 31, 2006 and $280.9 million at December 31, 2005, compared to
total revenues of $4.6 billion for 2006 and $4.8 billion for
2005.
Provisions
for Bad Debts and Allowances for Doubtful Accounts
As
of
each balance sheet date, the Company evaluates the collectibility of accounts
receivable and records allowances for doubtful accounts based on estimates
of
the level of expected write-offs. These estimates are based on, among other
things, comparisons of the relative age of accounts, assigned credit ratings
for
commercial and industrial accounts, credit scores for residential customers
in
Georgia when available, and consideration of actual write-off history. The
distribution segments of the Company’s regulated utilities have established
write-off histories and regulated service areas that tend to improve the
recoverability of accounts and enable the utilities to reliably estimate their
respective provisions for bad debts. The Company’s Retail Gas Marketing segment
operates in Georgia’s deregulated natural gas market in which customers may
obtain service from others without necessarily paying outstanding amounts and
in
which there are certain limitations on the Company’s ability to effect timely
shut-off of service for nonpayment. As such estimation of the provision for
bad
debts for these accounts is subject to greater imprecision.
Nuclear
Decommissioning
Accounting
for decommissioning costs for nuclear power plants involves significant
estimates related to costs to be incurred many years in the future. Among the
factors that could change SCE&G’s accounting estimates related to
decommissioning costs are changes in technology, changes in regulatory and
environmental remediation requirements, and changes in financial assumptions
such as discount rates and timing of cash flows. Changes in any of these
estimates could significantly impact the Company’s financial position and cash
flows (although changes in such estimates should be earnings-neutral, because
these costs are expected to be collected from ratepayers).
SCE&G’s
two-thirds share of estimated site-specific nuclear decommissioning costs for
Summer Station, including both the cost of decommissioning plant components
that
are and are not subject to radioactive contamination, totals
$451.0 million, stated in 2006 dollars, based on a decommissioning study
completed in 2006. Santee Cooper is responsible for decommissioning costs
related to its one-third ownership interest in Summer Station. The cost estimate
assumes that the site would be maintained over a period of 60 years in such
a manner as to allow for subsequent decontamination that would permit release
for unrestricted use.
Under
SCE&G’s method of funding decommissioning costs, amounts collected through
rates are invested in insurance policies on the lives of certain Company
personnel. SCE&G transfers to an external trust fund the amounts collected
through electric rates, insurance proceeds, and interest on proceeds, less
expenses. The trusteed asset balance reflects the net cash surrender value
of
the insurance policies held by the trust. Management intends for the fund,
including earnings thereon, to provide for all eventual decommissioning
expenditures on an after-tax basis.
Accounting
for Pensions and Other Postretirement Benefits
The
Company follows SFAS 87, “Employers’
Accounting for Pensions,” as
amended by SFAS 158, “Employees’
Accounting for Defined Benefit Pension and Other Postretirement Plans,”
in
accounting for the cost of its defined benefit pension plan. The Company’s plan
is adequately funded and as such, net pension income is reflected in the
financial statements (see Results of Operations-Pension
Income).
SFAS
87 requires the use of several assumptions, the selection of which may have
a
large impact on the resulting benefit recorded. Among the more sensitive
assumptions are those surrounding discount rates and expected returns on assets.
Net pension income of $13.5 million recorded in 2006 reflects the use of a
5.60%
discount rate and an assumed 9.00% long-term rate of return on plan assets. The
Company believes that these assumptions were, and that the resulting pension
income amount was, reasonable. For purposes of comparison, using a discount
rate
of 5.35% in 2006 would have decreased the Company’s pension income by $1.1
million. Had the assumed long-term rate of return on assets been 8.75%, the
Company’s pension income for 2006 would have been reduced by
$2.1 million.
For
2006,
the Company selected the discount rate of 5.60% which was derived using a cash
flow matching technique. For 2007, the discount rate to be used will be 5.85%,
which was derived using that same cash flow matching technique. The same
discount rates were also selected for determination of other postemployment
benefits costs discussed below.
The
following information with respect to pension assets (and returns thereon)
should also be noted.
The
Company determines the fair value of substantially all of its pension assets
utilizing market quotes rather than utilizing any calculated values, “market
related” values or other modeling techniques.
In
developing the expected long-term rate of return assumptions, the Company
evaluates input from actuaries and from pension fund investment consultants.
Such consultants’ 2006 review of the plan’s historical 10, 15, 20 and
25 year cumulative performance showed actual returns of 9.3%, 11.0%, 11.2%
and 12.7%, respectively, all of which have been in excess of related broad
indices. The 2006 expected long-term rate of return of 9.0% was based on a
target asset allocation of 70% with equity managers and 30% with fixed income
managers. Management regularly reviews such allocations and periodically
rebalances the portfolio when considered appropriate. For 2007, the expected
rate of return will be 9.0%.
The
pension trust is adequately funded, and no contributions have been required
since 1997. Management does not anticipate the need to make pension
contributions until after 2010.
Similar
to its pension accounting, the Company follows SFAS 106, “Employers’
Accounting for Postretirement Benefits Other Than Pensions,”
as
amended by SFAS 158 in accounting for the cost of its postretirement medical
and
life insurance benefits. This plan is unfunded, so no assumptions related to
rate of return on assets impact the net expense recorded; however, the selection
of discount rates can significantly impact the actuarial determination of net
expense. The Company used a discount rate of 5.60% and recorded a net
SFAS 106 cost of $22.3 million for 2006. Had the selected discount
rate been 5.35%, the expense for 2006 would have been $0.5 million higher.
Because the plan provisions include “caps” on company per capita costs,
healthcare cost inflation rate assumptions do not materially impact the net
expense recorded.
The
Company also adopted the balance sheet recognition provisions of SFAS 158
effective December 31, 2006, as more fully described in Note 3 to the
consolidated financial statements.
Asset
Retirement Obligations
SFAS 143,
“Accounting
for Asset Retirement Obligations,”
together
with Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting
for Conditional Asset Retirement Obligations,”
provides
guidance for recording and disclosing liabilities related to future legally
enforceable obligations to retire assets (ARO). SFAS 143 applies to the
legal obligation associated with the retirement of long-lived tangible assets
that result from their acquisition, construction, development and normal
operation. Because such obligation relates primarily to the Company’s regulated
utility operations, SFAS 143 and FIN 47 have no significant impact on
results of operations. As of December 31, 2006, the Company has recorded an
ARO
of $93 million for nuclear plant decommissioning (as discussed above) and an
ARO
of $199 million for other conditional obligations related to generation,
transmission and distribution properties, including gas pipelines. The ARO
for
nuclear plant decommissioning reflects a reduction of $46 million from the
corresponding ARO recorded as of December 31, 2005. The reduction is primarily
related to the expectation of lower decommissioning cost escalations than had
been assumed in the prior cash flow analysis. All of the amounts recorded in
connection with SFAS 143 and FIN 47 are based upon estimates which are subject
to varying degrees of imprecision, particularly since such payments will be
made
many years in the future. Changes in these estimates will be recorded over
time;
however, these changes in estimates are not expected to materially impact
results of operations so long as the regulatory framework for the Company’s
utilities remains in place.
Off-Balance
Sheet Financing
Although
SCANA invests in securities and business ventures, it does not hold investments
in unconsolidated special purpose entities such as those described in
SFAS 140, “Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities,”
or as
described in FIN 46(R), “Consolidation
of Variable Interest Entities.”
SCANA
does not engage in off-balance sheet financing or similar transactions, although
it is party to incidental operating leases in the normal course of business,
generally for office space, furniture and equipment.
Claims
and Litigation
For
a
description of claims and litigation see Item 3. LEGAL PROCEEDINGS and
Note 10 to the consolidated financial statements.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
All
financial instruments held by the Company described below are held for purposes
other than trading.
Interest
Rate Risk
The
tables below summarize long-term debt issued by the Company and other financial
instruments that are sensitive to changes in interest rates. For debt
obligations, the tables present principal cash flows and related weighted
average interest rates by expected maturity dates. For interest rate swaps,
the
figures shown reflect notional amounts and weighted average interest rates
and
related maturities. Fair values for debt and swaps represent quoted market
prices.
|
|
Expected
Maturity Date
|
|||||||
|
December 31,
2006
Millions
of dollars
|
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter
|
Total
|
Fair
Value
|
|
Long-Term
Debt:
|
|
|
|
|
|
|
|
|
|
Fixed
Rate ($)
|
33.2
|
123.2
|
108.2
|
14.8
|
619.3
|
2,023.6
|
2,922.3
|
3,020.0
|
|
Average
Fixed Interest Rate (%)
|
7.17
|
5.95
|
6.27
|
6.87
|
6.78
|
5.95
|
6.16
|
|
|
Variable
Rate ($)
|
100.0
|
100.0
|
100.2
|
|||||
|
Average
Variable Interest Rate (%)
|
5.52
|
5.52
|
||||||
|
Interest
Rate Swaps:
|
||||||||
|
Pay
Variable/Receive Fixed ($)
|
28.2
|
3.2
|
3.2
|
3.2
|
3.2
|
3.2
|
44.2
|
0.1
|
|
Average
Pay Interest Rate (%)
|
8.50
|
8.55
|
8.55
|
8.55
|
8.55
|
8.55
|
8.52
|
|
|
Average
Receive Interest Rate (%)
|
7.11
|
8.75
|
8.75
|
8.75
|
8.75
|
8.75
|
7.70
|
|
|
|
Expected
Maturity Date
|
|||||||
|
December 31,
2005
Millions
of dollars
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
Total
|
Fair
Value
|
|
Long-Term
Debt:
|
|
|
|
|
|
|
|
|
|
Fixed
Rate ($)
|
174.4
|
68.6
|
158.6
|
143.6
|
43.6
|
2,524.6
|
3,113.4
|
3,108.8
|
|
Average
Fixed Interest Rate (%)
|
8.50
|
6.96
|
6.13
|
6.39
|
6.99
|
6.14
|
6.47
|
|
|
Variable
Rate ($)
|
|
|
100.0
|
|
|
|
100.0
|
100.0
|
|
Average
Variable Interest Rate (%)
|
|
|
4.56
|
|
|
|
4.56
|
|
|
Interest
Rate Swaps:
|
|
|
|
|
|
|
|
|
|
Pay
Variable/Receive Fixed ($)
|
3.2
|
28.2
|
3.2
|
3.2
|
3.2
|
6.4
|
47.4
|
0.1
|
|
Average
Pay Interest Rate (%)
|
7.72
|
7.97
|
7.72
|
7.72
|
7.72
|
7.72
|
7.87
|
|
|
Average
Receive Interest Rate (%)
|
8.75
|
7.11
|
8.75
|
8.75
|
8.75
|
8.75
|
7.77
|
|
While
a
decrease in interest rates would increase the fair value of debt, it is unlikely
that events which would result in a realized loss will occur.
The
above
table excludes long-term debt of $80 million at December 31, 2006 and
$97 million at December 31, 2005, which amounts do not have a stated
interest rate associated with them.
Commodity
Price Risk
The
following table summarizes the Company’s financial instruments that are
sensitive to changes in natural gas prices. Weighted average settlement prices
are per 10,000 DT. Fair value represents quoted market prices.
|
Expected
Maturity:
|
|
|
|
|
|
|
|
|
|
|
Options
|
|||||||
|
|
Futures
Contracts
|
Purchased
Call
|
Purchased
Put
|
Sold
Put
|
||||
|
2007
|
Long
|
Short
|
(Long)
|
(Short)
|
(Long)
|
|||
|
|
|
|
|
|
|
|
|
|
|
Settlement
Price (a)
|
6.76
|
6.57
|
|
Strike
Price (a)
|
9.08
|
10.89
|
6.17
|
|
|
Contract
Amount (b)
|
37.0
|
4.3
|
|
Contract
Amount (b)
|
2.7
|
1.4
|
1.2
|
|
|
Fair
Value (b)
|
28.8
|
3.0
|
|
Fair
Value (b)
|
0.1
|
-
|
(0.1)
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement
Price (a)
|
8.31
|
-
|
|
Strike
Price (a)
|
-
|
-
|
-
|
|
|
Contract
Amount (b)
|
10.3
|
-
|
|
Contract
Amount (b)
|
-
|
-
|
-
|
|
|
Fair
Value (b)
|
9.8
|
-
|
|
Fair
Value (b)
|
-
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Weighted average, in dollars
|
|
|
|
|
|
|
||
|
(b)
Millions of dollars
|
||||||||
|
Swaps
|
2007
|
2008
|
2009
|
|
|
|
|
|
|
Commodity
Swaps:
|
|
|
|
|
Pay
fixed/receive variable (b)
|
190.9
|
78.3
|
0.3
|
|
Average
pay rate (a)
|
9.105
|
9.519
|
8.460
|
|
Average
received rate (a)
|
6.948
|
8.475
|
8.447
|
|
Fair
Value (b)
|
145.7
|
69.7
|
0.3
|
|
|
|
|
|
|
Pay
variable/receive fixed (b)
|
0.9
|
0.8
|
-
|
|
Average
pay rate (a)
|
7.333
|
8.111
|
-
|
|
Average
received rate (a)
|
8.361
|
8.011
|
-
|
|
Fair
Value (b)
|
1.1
|
0.8
|
-
|
|
|
|
|
|
|
Basis
Swaps:
|
|
|
|
|
Pay
variable/receive variable (b)
|
14.1
|
-
|
-
|
|
Average
pay rate (a)
|
6.331
|
-
|
-
|
|
Average
received rate (a)
|
6.319
|
-
|
-
|
|
Fair
Value (b)
|
14.1
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Weighted average, in dollars
|
|
|
|
|
(b)
Millions of dollars
|
The
Company uses derivative instruments to hedge forward purchases and sales of
natural gas, which create market risks of different types. See Note 9 to
the consolidated financial statements.
The
NYMEX
futures information above includes those financial positions of Energy
Marketing, SCE&G and PSNC Energy. SCE&G’s
tariffs include a purchased gas adjustment (PGA) clause that provides for the
recovery of actual gas costs incurred. The SCPSC has ruled that the results
of
these hedging activities are to be included in the PGA. As such, costs of
related derivatives utilized by SCE&G to hedge gas purchasing activities are
recoverable through the weighted average cost of gas calculation. The offset
to
the change in fair value of these derivatives is recorded as a regulatory asset
or liability. PSNC
Energy utilizes futures, options and swaps to hedge gas purchasing activities.
PSNC Energy’s tariffs include a provision for the recovery of actual gas costs
incurred. PSNC Energy records premiums, transaction fees, margin requirements
and any realized and unrealized gains or losses from its hedging program in
deferred accounts as a regulatory asset or liability for the over or under
recovery of gas costs.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
SCANA
Corporation:
We
have
audited the accompanying consolidated balance sheets of SCANA Corporation and
subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related
consolidated statements of income, changes in common equity and comprehensive
income, and of cash flows for each of the three years in the period ended
December 31, 2006. Our audits also included the financial statement schedule
listed in Part IV at Item 15. 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 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. An audit also includes assessing the accounting principles used
and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of SCANA Corporation and subsidiaries at
December 31, 2006 and 2005, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2006, in
conformity with accounting principles generally accepted in the United States
of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken
as a
whole, presents fairly in all material respects the information set forth
therein.
As
discussed in Note 3 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans,”
effective December 31, 2006.
We
have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Company’s internal
control over financial reporting as of December 31, 2006, based on the criteria
established in Internal Control-Integrated Framework issued by the Committee
of
Sponsoring Organizations of the Treadway Commission, and our report dated
February 28, 2007 expressed an unqualified opinion on management’s assessment of
the effectiveness of the Company’s internal control over financial reporting and
an unqualified opinion on the effectiveness of the Company’s internal control
over financial reporting.
/s/Deloitte
& Touche LLP
Columbia,
South Carolina
February
28, 2007
SCANA
Corporation
CONSOLIDATED
BALANCE SHEETS
|
December
31, (Millions of dollars)
|
|
2006
|
2005
|
|
|||
|
Assets
|
|
|
|
|
|
||
|
Utility
Plant In Service
|
|
$
|
9,227
|
|
$
|
8,999
|
|
|
Accumulated
Depreciation and Amortization
|
|
|
(2,815
|
)
|
|
(2,698
|
)
|
|
|
|
|
6,412
|
|
|
6,301
|
|
|
Construction
Work in Progress
|
|
|
326
|
|
|
175
|
|
|
Nuclear
Fuel, Net of Accumulated Amortization
|
|
|
39
|
|
|
28
|
|
|
Acquisition
Adjustments
|
|
|
230
|
|
|
230
|
|
|
Utility
Plant, Net
|
|
|
7,007
|
|
|
6,734
|
|
|
Nonutility
Property and Investments:
|
|
|
|
|
|
|
|
|
Nonutility property, net of accumulated depreciation of $70 and
$62
|
|
|
132
|
|
|
108
|
|
|
Assets held in trust, net-nuclear decommissioning
|
|
|
56
|
|
|
52
|
|
|
Other investments
|
|
|
88
|
|
|
87
|
|
|
Nonutility
Property and Investments, Net
|
|
|
276
|
|
|
247
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
201
|
|
|
62
|
|
|
Receivables, net of allowance for uncollectible accounts of $14 and
$25
|
|
|
655
|
|
|
881
|
|
|
Receivables-affiliated companies
|
|
|
32
|
|
|
24
|
|
|
Inventories (at average cost):
|
|
|
|
|
|
|
|
|
Fuel
|
|
|
300
|
|
|
284
|
|
|
Materials and supplies
|
|
|
93
|
|
|
79
|
|
|
Emission allowances
|
|
|
22
|
|
|
54
|
|
|
Prepayments and other
|
|
|
39
|
|
|
54
|
|
|
Deferred income taxes
|
|
|
34
|
|
|
26
|
|
|
Total Current Assets
|
|
|
1,376
|
|
|
1,464
|
|
|
Deferred
Debits:
|
|
|
|
|
|
|
|
|
Pension asset, net
|
|
|
200
|
|
|
303
|
|
|
Emission allowances
|
27
|
-
|
|||||
|
Regulatory assets
|
|
|
792
|
|
|
617
|
|
|
Other
|
|
|
139
|
|
|
154
|
|
|
Total Deferred Debits
|
|
|
1,158
|
|
|
1,074
|
|
|
Total
|
|
$
|
9,817
|
|
$
|
9,519
|
|
|
December
31, (Millions of dollars)
|
|
2006
|
2005
|
|
|||
|
Capitalization
and Liabilities
|
|
|
|
|
|
||
|
Shareholders’
Investment:
|
|
|
|
|
|
|
|
|
Common equity
|
|
$
|
2,846
|
|
$
|
2,677
|
|
|
Preferred stock (Not subject to purchase or sinking funds)
|
|
|
106
|
|
|
106
|
|
|
Total
Shareholders’ Investment
|
|
|
2,952
|
|
|
2,783
|
|
|
Preferred
Stock, Net (Subject to purchase or sinking funds)
|
|
|
8
|
|
|
8
|
|
|
Long-Term
Debt, Net
|
|
|
3,067
|
|
|
2,948
|
|
|
Total Capitalization
|
|
|
6,027
|
|
|
5,739
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Short-term borrowings
|
|
|
487
|
|
|
427
|
|
|
Current portion of long-term debt
|
|
|
43
|
|
|
188
|
|
|
Accounts payable
|
|
|
414
|
|
|
471
|
|
|
Accounts payable-affiliated companies
|
|
|
27
|
|
|
26
|
|
|
Customer deposits and customer prepayments
|
|
|
85
|
|
|
70
|
|
|
Taxes accrued
|
|
|
121
|
|
|
112
|
|
|
Interest accrued
|
|
|
51
|
|
|
52
|
|
|
Dividends declared
|
|
|
51
|
|
|
47
|
|
|
Other
|
|
|
126
|
|
|
107
|
|
|
Total Current Liabilities
|
|
|
1,405
|
|
|
1,500
|
|
|
Deferred
Credits:
|
|
|
|
|
|
|
|
|
Deferred income taxes, net
|
|
|
947
|
|
|
940
|
|
|
Deferred investment tax credits
|
|
|
120
|
|
|
121
|
|
|
Asset retirement obligations
|
|
|
292
|
|
|
322
|
|
|
Postretirement benefits
|
|
|
194
|
|
|
148
|
|
|
Regulatory liabilities
|
|
|
714
|
|
|
605
|
|
|
Other
|
|
|
118
|
|
|
144
|
|
|
Total Deferred Credits
|
|
|
2,385
|
|
|
2,280
|
|
|
Commitments
and Contingencies (Note 10)
|
|
|
-
|
|
|
-
|
|
|
Total
|
|
$
|
9,817
|
|
$
|
9,519
|
|
See
Notes
to Consolidated Financial Statements.
SCANA
Corporation
CONSOLIDATED
STATEMENTS OF INCOME
|
Years
Ended December 31, (Millions of dollars, except per share
amounts)
|
|
2006
|
|
2005
|
|
2004
|
|
||||||
|
Operating
Revenues:
|
|
|
|
|
|
|
|||||||
|
Electric
|
|
$
|
1,877
|
|
$
|
1,909
|
|
$
|
1,688
|
|
|||
|
Gas-regulated
|
|
|
1,257
|
|
|
1,405
|
|
|
1,126
|
|
|||
|
Gas-nonregulated
|
|
|
1,429
|
|
|
1,463
|
|
|
1,071
|
|
|||
|
Total Operating Revenues
|
|
|
4,563
|
|
|
4,777
|
|
|
3,885
|
|
|||
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
|
||||
|
Fuel used in electric generation
|
|
|
615
|
|
|
618
|
|
|
467
|
|
|||
|
Purchased power
|
|
|
28
|
|
|
37
|
|
|
51
|
|
|||
|
Gas purchased for resale
|
|
|
2,213
|
|
|
2,399
|
|
|
1,753
|
|
|||
|
Other operation and maintenance
|
|
|
619
|
|
|
632
|
|
|
608
|
|
|||
|
Depreciation and amortization
|
|
|
333
|
|
|
510
|
|
|
265
|
|
|||
|
Other taxes
|
|
|
152
|
|
|
145
|
|
|
145
|
|
|||
|
Total Operating Expenses
|
|
|
3,960
|
|
|
4,341
|
|
|
3,289
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Operating
Income
|
|
|
603
|
|
|
436
|
|
|
596
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
|
||||
|
Other revenues
|
|
|
142
|
|
|
248
|
|
|
181
|
|
|||
|
Other expenses
|
|
|
(93
|
)
|
|
(200
|
)
|
|
(160
|
)
|
)
|
||
|
Interest charges, net of allowance for borrowed funds used during
construction of $8,
$3 and $10
|
|
|
(209
|
)
|
|
(212
|
)
|
|
(202
|
)
|
)
|
||
|
Gain (loss) on sale of investments and assets
|
|
|
3
|
|
|
9
|
|
|
(20
|
)
|
)
|
||
|
Investment impairments
|
|
|
-
|
|
|
-
|
|
|
(27
|
)
|
)
|
||
|
Preferred dividends of subsidiary
|
|
|
(7
|
)
|
|
(7
|
)
|
|
(7
|
)
|
)
|
||
|
Allowance for equity funds used during construction
|
|
|
-
|
|
|
-
|
|
|
16
|
|
|||
|
Total Other Expense
|
|
|
(164
|
)
|
|
(162
|
)
|
|
(219
|
)
|
)
|
||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Income
Before Income Taxes (Benefit) and Earnings (Losses) from
Equity Method Investments and Cumulative Effect of Accounting
Change
|
|
|
439
|
|
274
|
|
|
377
|
|
||||
|
Income
Tax Expense (Benefit)
|
|
|
119
|
|
(118
|
)
|
|
123
|
|
||||
|
Income
Before Earnings (Losses) from Equity Method Investments
|
|
|
|
|
|
|
|
|
|
||||
|
and Cumulative Effect of Accounting Change
|
|
|
320
|
|
|
392
|
|
|
254
|
|
|||
|
Earnings
(Losses) from Equity Method Investments
|
|
|
(16
|
)
|
|
(72
|
)
|
|
3
|
|
|||
|
Cumulative
Effect of Accounting Change, net of taxes
|
6
|
-
|
-
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net
Income
|
|
$
|
310
|
|
$
|
320
|
|
$
|
257
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Basic
and Diluted Earnings Per Share of Common Stock:
|
|
|
|||||||||||
|
Before
Cumulative Effect of Accounting Change
|
$
|
2.63
|
$
|
2.81
|
$
|
2.30
|
|||||||
|
Cumulative
Effect of Accounting Change, net of taxes
|
.05
|
-
|
-
|
||||||||||
|
Basic
and Diluted Earnings Per Share
|
$
|
2.68
|
$
|
2.81
|
$
|
2.30
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
||||
|
Weighted
Average Common Shares Outstanding (Millions)
|
|
|
115.8
|
|
|
113.8
|
|
|
111.6
|
|
|||
See
Notes
to Consolidated Financial Statements.
SCANA
Corporation
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For
the Years Ended December 31, (Millions of dollars)
|
|
2006
|
|
2005
|
|
2004
|
|
|||
|
Cash
Flows From Operating Activities:
|
|
|
|
|
|
|
|
|||
|
Net
Income
|
|
$
|
310
|
$
|
320
|
|
$
|
257
|
||
|
Adjustments
to reconcile net income to net cash provided from operating activities:
|
|
|
|
|
|
|
|
|||
|
Cumulative effect of accounting change, net of taxes
|
(6
|
)
|
-
|
-
|
||||||
|
Excess losses (earnings), net of distributions from equity method
investments
|
|
|
23
|
|
72
|
|
|
(3
|
)
|
|
|
Depreciation and amortization
|
|
|
347
|
|
518
|
|
|
274
|
||
|
Amortization of nuclear fuel
|
|
|
17
|
|
18
|
|
|
22
|
||
|
(Gain) loss on sale of assets and investments
|
|
|
(3
|
)
|
|
(9
|
)
|
|
20
|
|
|
Impairment of investments
|
|
|
-
|
|
-
|
|
|
27
|
||
|
Hedging activities
|
|
|
(15
|
)
|
|
4
|
|
|
11
|
|
|
Allowance for equity funds used during construction
|
|
|
-
|
|
-
|
|
|
(16
|
)
|
|
|
Carrying cost recovery
|
|
|
(7
|
)
|
|
(11
|
)
|
|
-
|
|
|
Cash provided (used) by changes in certain assets and
liabilities:
|
|
|
|
|
|
|
|
|||
|
Receivables, net
|
|
|
218
|
|
(174
|
)
|
|
(225
|
)
|
|
|
Inventories
|
|
|
(80
|
)
|
|
(188
|
)
|
|
(90
|
)
|
|
Prepayments and other
|
|
|
(2
|
)
|
|
-
|
|
|
(2
|
)
|
|
Pension asset
|
|
|
(13
|
)
|
|
(17
|
)
|
|
(14
|
)
|
|
Other regulatory assets
|
|
|
(32
|
)
|
|
(28
|
)
|
|
(17
|
)
|
|
Deferred income taxes, net
|
|
|
5
|
|
25
|
|
|
74
|
||
|
Regulatory liabilities
|
|
|
9
|
|
(159
|
)
|
|
48
|
||
|
Postretirement benefits obligations
|
|
|
(3
|
)
|
|
6
|
|
|
7
|
|
|
Accounts payable
|
|
|
(77
|
)
|
|
79
|
|
|
91
|
|
|
Taxes accrued
|
|
|
9
|
|
(20
|
)
|
|
23
|
||
|
Interest accrued
|
|
|
(1
|
)
|
|
1
|
|
|
(4
|
)
|
|
Changes
in fuel adjustment clauses
|
|
|
3
|
|
(7
|
)
|
|
(3
|
)
|
|
|
Changes
in other assets
|
|
|
30
|
|
(17
|
)
|
|
22
|
||
|
Changes
in other liabilities
|
|
|
21
|
|
54
|
|
|
77
|
||
|
Net
Cash Provided From Operating Activities
|
|
|
753
|
|
467
|
|
|
579
|
||
|
Cash
Flows From Investing Activities:
|
|
|
|
|
|
|
|
|||
|
Utility property additions and construction expenditures, including
debt AFC
|
|
|
(485
|
)
|
|
(366
|
)
|
|
(478
|
)
|
|
Proceeds from sale of assets and investments
|
|
|
21
|
|
10
|
|
|
68
|
||
|
Nonutility property additions
|
|
|
(42
|
)
|
|
(19
|
)
|
|
(23
|
)
|
|
Investments
|
|
|
(25
|
)
|
|
(18
|
)
|
|
(20
|
)
|
|
Net
Cash Used For Investing Activities
|
|
|
(531
|
)
|
|
(393
|
)
|
|
(453
|
)
|
|
Cash
Flows From Financing Activities:
|
|
|
|
|
|
|
|
|||
|
Proceeds from issuance of common stock
|
|
|
79
|
|
84
|
|
|
65
|
||
|
Proceeds from issuance of debt
|
|
|
132
|
|
221
|
|
|
136
|
||
|
Repayments of debt
|
|
|
(156
|
)
|
|
(470
|
)
|
|
(169
|
)
|
|
Redemption/repurchase of equity securities
|
|
|
-
|
|
(1
|
)
|
|
(4
|
)
|
|
|
Dividends
|
|
|
(198
|
)
|
|
(181
|
)
|
|
(168
|
)
|
|
Short-term borrowings, net
|
|
|
60
|
|
216
|
|
|
16
|
||
|
Net
Cash Used For Financing Activities
|
|
|
(83
|
)
|
|
(131
|
)
|
|
(124
|
)
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
139
|
|
(57
|
)
|
|
2
|
||
|
Cash
and Cash Equivalents, January 1
|
|
|
62
|
|
119
|
|
|
117
|
||
|
Cash
and Cash Equivalents, December 31
|
|
$
|
201
|
$
|
62
|
|
$
|
119
|
||
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
|||
|
Cash
paid for-Interest (net of capitalized interest of $8, $3 and
$10)
|
|
$
|
212
|
$
|
213
|
|
$
|
206
|
||
|
-Income taxes
|
|
|
100
|
|
58
|
|
|
24
|
||
|
Noncash
Investing and Financing Activities:
|
|
|
|
|
|
|
|
|||
|
Unrealized loss on securities available for sale, net of
tax
|
|
|
-
|
|
-
|
|
|
(2
|
)
|
|
|
Accrued construction expenditures
|
|
|
54
|
|
36
|
|
|
49
|
|
|
See
Notes
to Consolidated Financial Statements.
SCANA
Corporation
CONSOLIDATED
STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
|
|
|
Accumulated
|
|
||||||||||||||
|
|
|
|
|
|
Other
|
|
||||||||||||||
|
|
|
Common
Stock
|
|
Retained
|
Comprehensive
|
|
||||||||||||||
|
Millions
|
|
Shares
|
Amount
|
|
Earnings
|
Income
(Loss)
|
Total
|
|
||||||||||||
|
|
|
|
||||||||||||||||||
|
Balance
as of December 31, 2003
|
111
|
$
|
1,187
|
$
|
1,113
|
$
|
6
|
$
|
2,306
|
|||||||||||
|
Comprehensive
Income:
|
||||||||||||||||||||
|
Net Income
|
|
|
|
|
|
|
|
|
257
|
|
|
|
|
257
|
|
|||||
|
Changes in Other Comprehensive Income (Loss) net of
taxes $(5)
|
(10
|
)
|
(10
|
)
|
||||||||||||||||
|
Total Comprehensive Income
|
|
|
|
|
|
|
|
|
257
|
|
|
(10
|
)
|
|
247
|
|
||||
|
Issuance
of Common Stock
|
|
|
2
|
|
|
65
|
|
|
|
|
|
|
|
|
65
|
|
||||
|
Repurchase
of Common Stock
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
(4
|
)
|
||||
|
Dividends
Declared on Common Stock
|
|
|
|
|
|
|
|
|
(163
|
)
|
|
|
|
|
(163
|
)
|
||||
|
Balance
as of December 31, 2004
|
|
|
113
|
|
$
|
1,248
|
|
$
|
1,207
|
|
$
|
(4
|
)
|
$
|
2,451
|
|
||||
|
Comprehensive
Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net Income
|
|
|
|
|
|
|
|
|
320
|
|
|
|
|
|
320
|
|
||||
|
Changes in Other Comprehensive Income (Loss), net of
taxes $-
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
-
|
|||||
|
Total Comprehensive Income
|
|
|
|
|
|
|
|
|
320
|
|
|
-
|
|
|
320
|
|
||||
|
Issuance
of Common Stock
|
|
|
2
|
|
|
84
|
|
|
|
|
|
|
|
|
84
|
|
||||
|
Dividends
Declared on Common Stock
|
|
|
|
|
|
|
|
|
(178
|
)
|
|
|
|
|
(178
|
)
|
||||
|
Balance
as of December 31, 2005
|
|
|
115
|
|
$
|
1,332
|
|
$
|
1,349
|
|
$
|
(4
|
)
|
$
|
2,677
|
|
||||
|
Comprehensive
Income (Loss):
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Net Income
|
|
|
310
|
310
|
|
|||||||||||||||
|
Changes
in Other Comprehensive Income (Loss), net of
taxes $(8)
|
|
|
(14
|
)
|
(14
|
)
|
||||||||||||||
|
Total Comprehensive Income
|
|
|
310
|
(14
|
)
|
296
|
|
|||||||||||||
|
Deferred
Cost of Employee Benefit Plans, net of taxes $(7)
|
(11
|
)
|
(11)
|
|||||||||||||||||
|
Issuance
of Common Stock
|
|
|
2
|
79
|
79
|
|
||||||||||||||
|
Dividends
Declared on Common Stock
|
|
|
(195
|
)
|
(195
|
)
|
||||||||||||||
|
Balance
as of December 31, 2006
|
|
|
117
|
$
|
1,411
|
$
|
1,464
|
$
|
(29
|
)
|
$
|
2,846
|
|
|||||||
The
Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated
other
comprehensive income gains, losses, prior service costs and credits that
have
not yet been recognized through net periodic benefit cost, net of tax
effects.
See
Notes
to Consolidated Financial Statements.
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization
and Principles of Consolidation
SCANA
Corporation (SCANA, and together with its consolidated subsidiaries, the
Company), a South Carolina corporation, is a holding company. The Company
engages predominantly in the generation and sale of electricity to wholesale
and
retail customers in South Carolina and in the purchase, sale and transportation
of natural gas to wholesale and retail customers in South Carolina, North
Carolina and Georgia. The Company also conducts other energy-related businesses
and provides fiber optic communications in South Carolina.
The
accompanying Consolidated Financial Statements reflect the accounts of SCANA,
the following wholly owned subsidiaries, and one other wholly owned subsidiary
in liquidation.
|
Regulated
businesses
|
Nonregulated
businesses
|
|
South
Carolina Electric & Gas Company (SCE&G)
|
SCANA
Energy Marketing, Inc.
|
|
South
Carolina Fuel Company, Inc. (Fuel Company)
|
SCANA
Communications, Inc. (SCI)
|
|
South
Carolina Generating Company, Inc. (GENCO)
|
ServiceCare,
Inc.
|
|
Public
Service Company of North Carolina, Incorporated (PSNC
Energy)
|
Primesouth, Inc.
|
|
Carolina
Gas Transmission Corporation (CGTC)
|
SCANA
Resources, Inc.
|
|
SCANA
Services, Inc.
|
|
|
SCANA
Corporate Security Services, Inc.
|
Effective
November 1, 2006, CGTC began operating as an open access, transportation-only
interstate pipeline company. CGTC resulted from the merger of SCG Pipeline,
Inc.
into South Carolina Pipeline Corporation (SCPC), both of which were wholly
owned
subsidiaries of SCANA. SCPC was subsequently renamed CGTC.
The
Company reports certain investments using the cost or equity method of
accounting, as appropriate. Significant intercompany balances and transactions
have been eliminated in consolidation except as permitted by Statement of
Financial Accounting Standards (SFAS) 71, “Accounting
for the Effects of Certain Types of Regulation,”
which
provides that profits on intercompany sales to regulated affiliates are not
eliminated if the sales price is reasonable and the future recovery of the
sales
price through the rate-making process is probable.
B. Basis
of Accounting
The
Company accounts for its regulated utility operations, assets and liabilities
in
accordance with the provisions of SFAS 71, which requires cost-based
rate-regulated utilities to recognize in their financial statements certain
revenues and expenses in different time periods than do enterprises that are
not
rate-regulated. As a result, the Company has recorded the regulatory assets
and
regulatory liabilities summarized as follows.
|
|
|
December 31,
|
|
||||
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Regulatory
Assets:
|
|
|
|||||
|
Accumulated
deferred income taxes
|
|
$
|
174
|
|
$
|
177
|
|
|
Under-collections-electric
fuel and gas cost adjustment clauses
|
|
|
95
|
|
|
61
|
|
|
Purchased
power costs
|
|
|
9
|
|
|
17
|
|
|
Environmental
remediation costs
|
|
|
29
|
|
|
28
|
|
|
Asset
retirement obligations and related funding
|
|
|
264
|
|
|
250
|
|
|
Franchise
agreements
|
|
|
55
|
|
|
56
|
|
|
Regional
transmission organization costs
|
|
|
8
|
|
|
11
|
|
|
Deferred
employee benefit plan costs
|
142
|
-
|
|||||
|
Other
|
|
|
16
|
|
17
|
||
|
Total
Regulatory Assets
|
|
$
|
792
|
|
$
|
617
|
|
|
|
|
December 31,
|
|
||||
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Regulatory
Liabilities:
|
|||||||
|
Accumulated
deferred income taxes
|
$
|
38
|
$
|
39
|
|||
|
Over-collections-electric
fuel and gas cost adjustment clauses
|
|
|
8
|
|
|
20
|
|
|
Other
asset removal costs
|
599
|
488
|
|||||
|
Storm
damage reserve
|
|
|
44
|
|
38
|
||
|
Planned
major maintenance
|
6
|
9
|
|||||
|
Other
|
|
|
19
|
|
11
|
||
|
Total
Regulatory Liabilities
|
|
$
|
714
|
|
$
|
605
|
|
Accumulated
deferred income tax liabilities arising from utility operations that have not
been included in customer rates are recorded as a regulatory asset. Accumulated
deferred income tax assets arising from deferred investment tax credits are
recorded as a regulatory liability.
Under-
and over-collections-electric fuel and gas cost adjustment clauses, net,
represent amounts under- or over-collected from customers pursuant to the fuel
adjustment clause (electric customers) or gas cost adjustment clause (gas
customers) as approved by the Public Service Commission of South Carolina
(SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings.
Included in these amounts are regulatory assets or liabilities arising from
the
natural gas hedging programs of the Company’s regulated operations. See
Notes 1E and 1L.
Purchased
power costs represents costs necessitated by outages at two of SCE&G’s base
load generating plants in winter 2000-2001. The SCPSC approved recovery of
these
costs in base rates over a three-year period beginning January 2005.
Environmental
remediation costs represent costs associated with the assessment and clean-up
of
manufactured gas plant (MGP) sites currently or formerly owned by the Company.
Costs incurred at sites owned by SCE&G are being recovered through rates, of
which approximately $17.9 million remain to be recovered. Through
June 30, 2006, PSNC Energy incurred and deferred $3.6 million in costs, net
of
insurance settlements, that were not being recovered through rates. In
connection with an October 2006 NCUC rate order, such costs are now being
recovered through rates over a three-year period. In addition, management
believes that costs incurred subsequent to June 30, 2006, totaling $0.9 million
at December 31, 2006, and the estimated remaining costs of $6.9 million, will
be
recoverable by PSNC Energy through rates.
Asset
retirement obligations (ARO) and related funding represents the regulatory
asset
associated with the legal obligation to decommission and dismantle V. C. Summer
Nuclear Station (Summer Station) and conditional AROs recorded as required
by
SFAS 143,
“Accounting for Asset Retirement Obligations,” and
Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting
for Conditional Asset Retirement Obligations.”
Franchise
agreements represent costs associated with electric and gas franchise agreements
with the cities of Charleston and Columbia, South Carolina. SCE&G is
amortizing these amounts through cost of service rates and are expected to
be
amortized over approximately 20 years.
Regional
transmission organization costs represent costs incurred by SCE&G in the
United States Federal Energy Regulatory Commission (FERC)-mandated formation
of
GridSouth. The project was suspended in 2002. Effective January 2005, the
SCPSC approved the amortization of these amounts through cost of service rates
over approximately five years.
Deferred
employee benefit plan costs represent amounts of
pension and other postretirement benefit costs which were accrued as liabilities
under provisions of SFAS 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement
Plans,”
but
which are expected to be recovered through utility rates (see Note 3).
Other
asset removal costs represent net collections through depreciation rates of
estimated costs to be incurred for the removal of assets in the future.
The
storm
damage reserve represents an SCPSC-approved reserve account for SCE&G capped
at $50 million to be collected through rates. The accumulated reserve can
be applied to offset incremental storm damage costs in excess of $2.5 million
in
a calendar year. During the years ended December 31, 2006 and 2005, no
significant amounts were drawn from this reserve account.
Planned
major maintenance related to certain fossil and hydro-turbine equipment and
nuclear refueling outages is accrued in advance of the time the costs are
incurred, as approved through specific SCPSC orders. SCE&G is allowed to
collect $8.5 million annually over an eight-year period through electric rates
to offset turbine maintenance expenditures. Nuclear refueling charges are
accrued during each 18-month refueling outage cycle and are a component of
cost
of service and do not receive special rate consideration.
The
SCPSC
and the NCUC (collectively, state commissions) have reviewed and approved
through specific orders most of the items shown as regulatory assets. Other
items represent costs which are not yet approved for recovery by a state
commission. In recording these costs as regulatory assets, management believes
the costs will be allowable under existing rate-making concepts that are
embodied in rate orders received by the Company. However, ultimate recovery
is
subject to state commission approval. In the future, as a result of deregulation
or other changes in the regulatory environment, the Company may no longer meet
the criteria for continued application of SFAS 71 and could be required to
write
off its regulatory assets and liabilities. Such an event could have a material
adverse effect on the Company’s results of operations, liquidity or financial
position in the period the write-off would be recorded.
C. Utility
Plant and Major Maintenance
Utility
plant is stated substantially at original cost. The costs of additions, renewals
and betterments to utility plant, including direct labor, material and indirect
charges for engineering, supervision and an allowance for funds used during
construction, are added to utility plant accounts. The original cost of utility
property retired or otherwise disposed of is removed from utility plant accounts
and generally charged to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a
unit
of property or that do not increase the asset’s life or functionality are
charged to maintenance expense.
SCE&G,
operator of Summer Station, and the South Carolina Public Service Authority
(Santee Cooper) jointly own Summer Station in the proportions of two-thirds
and
one-third, respectively. The parties share the operating costs and energy output
of the plant in these proportions. Each party, however, provides its own
financing. Plant-in-service related to SCE&G’s portion of Summer Station was
$1.0 billion as of December 31, 2006 and 2005 (including amounts
related to ARO). Accumulated depreciation associated with SCE&G’s share of
Summer Station was $496.8 million and $478.7 million as of
December 31, 2006 and 2005, respectively (including amounts related to
ARO). SCE&G’s share of the direct expenses associated with operating Summer
Station is included in other operation and maintenance expenses and totaled
$77.7 million for 2006, $76.3 million for 2005 and $74.5 million
for 2004.
Planned
major maintenance related to certain fossil and hydro turbine equipment and
nuclear refueling outages is accrued in advance of the time the costs are
actually incurred in accordance with approval by the SCPSC for such accounting
treatment and rate recovery of expenses accrued thereunder. Other planned major
maintenance is expensed when incurred. Beginning in 2005, SCE&G is
collecting $8.5 million annually over an eight-year period through electric
rates to offset turbine maintenance expenditures. For the year ended December
31, 2006, SCE&G incurred $7.2 million for turbine maintenance. The remaining
$1.3 million is in a regulatory liability account on the balance sheet. Nuclear
refueling outages are scheduled 18 months apart, and SCE&G begins
accruing for each successive outage upon completion of the preceding outage.
SCE&G accrued $1.0 million per month from July 2005 through
December 2006 for its portion of the outage in October 2006 and is
accruing $1.1 million per month for its portion of the outage scheduled for
the
spring of 2008. Total costs for the 2006 outage were $25.5 million, of
which SCE&G was responsible for $17.0 million. As of December 31,
2006 and 2005, SCE&G had accrued $0.2 million and $5.7 million,
respectively.
D.
Allowance
for Funds Used During Construction (AFC)
AFC
is a
noncash item that reflects the period cost of capital devoted to plant under
construction. This accounting practice results in the inclusion of, as a
component of construction cost, the costs of debt and equity capital dedicated
to construction investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates for utility
services. The Company’s regulated subsidiaries calculated AFC using composite
rates of 5.5%, 4.9% and 6.9% for 2006, 2005 and 2004, respectively. These rates
do not exceed the maximum allowable rate as calculated under FERC Order
No. 561. SCE&G capitalizes interest on nuclear fuel in process at the
actual interest amount incurred.
E. Revenue
Recognition
The
Company records revenues during the accounting period in which it provides
services to customers and includes estimated amounts for electricity and natural
gas delivered, but not yet billed. Unbilled revenues totaled $177.6 million
at
December 31, 2006 and $280.9 million at December 31,
2005.
Fuel
costs for electric generation are collected through the fuel cost component
in
retail electric rates. This component is established by the SCPSC during annual
fuel cost hearings. Any difference between actual fuel costs and amounts
contained in the fuel cost component is deferred and included when determining
the fuel cost component during the next annual hearing. SCE&G had
undercollected through the electric fuel cost component $28.9 million and
$44.1 million at December 31, 2006 and 2005, respectively, which
amounts are included in other regulatory assets.
Customers
subject to the gas cost adjustment clause are billed based on a fixed cost
of
gas determined by the state commission during annual gas cost recovery hearings.
Any difference between actual gas costs and amounts contained in rates is
deferred and included when establishing gas costs during the next annual
hearing. At December 31, 2006 and 2005, SCE&G had undercollected $20.3
million and $11.8 million, respectively, which amounts are also included in
other regulatory assets. At December 31, 2006 and 2005, PSNC Energy had
undercollected $38.5 million, net, and overcollected $15.1 million, net,
respectively, which amounts are included in other regulatory assets or
liabilities.
SCE&G’s
and PSNC Energy’s gas rate schedules for residential, small commercial and small
industrial customers include a weather normalization adjustment which minimizes
fluctuations in gas revenues due to abnormal weather conditions.
F. Depreciation
and Amortization
The
Company records provisions for depreciation and amortization using the
straight-line method based on the estimated service lives of the various classes
of property. The composite weighted average depreciation rates for utility
plant
assets were as follows:
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
SCE&G
|
|
|
3.19
|
%
|
3.20
|
%
|
|
2.99
|
%
|
|
|
GENCO
|
|
|
2.66
|
%
|
2.66
|
%
|
|
2.66
|
%
|
|
|
CGTC
|
|
|
2.04
|
%
|
2.01
|
%
|
|
2.04
|
%
|
|
|
PSNC
Energy
|
|
|
3.69
|
%
|
3.77
|
%
|
|
3.87
|
%
|
|
|
Aggregate
of Above
|
|
|
3.19
|
%
|
3.20
|
%
|
|
3.04
|
%
|
|
SCE&G
records nuclear fuel amortization using the units-of-production method. Nuclear
fuel amortization is included in “Fuel used in electric generation” and
recovered through the fuel cost component of retail electric rates. Provisions
for amortization of nuclear fuel include amounts necessary to satisfy
obligations to the Department of Energy (DOE) under a contract for disposal
of
spent nuclear fuel.
The
Company considers amounts categorized by FERC as “acquisition adjustments” to be
goodwill as defined in SFAS 142, “Goodwill
and Other Intangible Assets,”
and has
ceased amortization of such amounts. These amounts are related to acquisition
adjustments of approximately $466 million ($210 million net of accumulated
amortization) recorded by PSNC Energy (Gas Distribution segment) and
approximately $40 million ($20 million net of accumulated amortization)
recorded by CGTC
(Gas
Transmission segment). In accordance with SFAS 142, the Company performs an
annual impairment evaluation of its investment in PSNC Energy and CGTC. These
calculations have indicated no need for write-downs of acquisition adjustments
in 2006 and 2005. Should a write-down be required in the future, such a charge
would be treated as an operating expense.
G. Nuclear
Decommissioning
SCE&G’s
two-thirds share of estimated site-specific nuclear decommissioning costs for
Summer Station, including the cost of decommissioning plant components both
subject to and not subject to radioactive contamination, totals
$451.0 million, stated in 2006 dollars, based on a decommissioning study
completed in 2006. Santee Cooper is responsible for decommissioning costs
related to its one-third ownership interest in Summer Station. The cost estimate
assumes that the site would be maintained over a period of 60 years in such
a manner as to allow for subsequent decontamination that would permit release
for unrestricted use.
Under
SCE&G’s method of funding decommissioning costs, amounts collected through
rates ($3.2 million pre-tax in each of 2006, 2005 and 2004) are invested in
insurance policies on the lives of certain Company personnel. SCE&G
transfers to an external trust fund the amounts collected through electric
rates, insurance proceeds, and interest on proceeds, less expenses. The trusteed
asset balance reflects the net cash surrender value of the insurance policies
and cash held by the trust. Management intends for the fund, including earnings
thereon, to provide for all eventual decommissioning expenditures on an
after-tax basis.
H. Income
and Other Taxes
The
Company files a consolidated federal income tax return. Under a joint
consolidated income tax allocation agreement, each subsidiary’s current and
deferred tax expense is computed on a stand-alone basis. Deferred tax assets
and
liabilities are recorded for the tax effects of all significant temporary
differences between the book basis and tax basis of assets and liabilities
at
currently enacted tax rates. Deferred tax assets and liabilities are adjusted
for changes in such tax rates through charges or credits to regulatory assets
or
liabilities if they are expected to be recovered from, or passed through to,
customers of the Company’s regulated subsidiaries; otherwise, they are charged
or credited to income tax expense.
The
Company records excise taxes billed and collected, as well as local franchise
and similar taxes, as liabilities until they are remitted to the respective
taxing authority. Accordingly, no such taxes are included in revenues or
expenses in the statements of income.
I.
Debt
Premium, Discount and Expense, Unamortized Loss on Reacquired
Debt
The
Company records long-term debt premium and discount in long-term debt and
amortizes them as components of interest charges over the terms of the
respective debt issues. Other issuance expense and gains or losses on reacquired
debt that is refinanced are recorded in other deferred debits or credits and
amortized over the term of the replacement debt.
J.
Environmental
The
Company maintains an environmental assessment program to identify and evaluate
current and former operations sites that could require environmental cleanup.
As
site assessments are initiated, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates.
K.
Cash
and Cash Equivalents
The
Company considers temporary cash investments having original maturities of
three
months or less at time of purchase to be cash equivalents. These cash
equivalents are generally in the form of commercial paper, certificates of
deposit, repurchase agreements, treasury bills and notes.
L. Commodity
Derivatives
The
Company records derivatives contracts at their fair value in accordance with
SFAS 133, “Accounting
for Derivative Instruments and Hedging Activities,”
as
amended, and adjusts fair value each reporting period. The Company determines
fair value of most of the energy-related derivatives contracts using quotations
from markets where they are actively traded. For other derivatives contracts,
the Company uses published market surveys and, in certain cases, independent
parties to obtain quotes concerning fair value. Market quotes tend to be more
plentiful for those derivatives contracts maturing in two years or less. The
Company’s derivatives contracts do not extend beyond two years. See
Note 9.
The
Company’s regulated gas operations (SCE&G and PSNC Energy) hedge gas
purchasing activities using over-the-counter options and swaps and New York
Mercantile Exchange (NYMEX) futures and options. SCE&G’s tariffs include a
purchased gas adjustment (PGA) clause that provides for the recovery of actual
gas costs incurred. The SCPSC has ruled that the results of these hedging
activities are to be included in the PGA. As such, costs of related derivatives
utilized to hedge gas purchasing activities are recoverable through the weighted
average cost of gas calculation. The offset to the change in fair value of
these
derivatives is recorded as a regulatory asset or liability. PSNC Energy's
tariffs include a provision for the recovery of actual gas costs incurred.
PSNC
Energy records premiums, transaction fees, margin requirements and any realized
and unrealized gains or losses from its hedging program in deferred accounts
as
a regulatory asset or liability for the over- or under-recovery of gas
costs.
M. New
Accounting Matters
SFAS
123(R) requires compensation costs related to share-based payment transactions
to be recognized in the financial statements. With limited exceptions,
compensation cost is measured based on the grant-date fair value of the
instruments issued and is recognized over the period that an employee provides
service in exchange for the award. SFAS 123(R) replaced SFAS 123, “Accounting
for Stock-Based Compensation,” and
superseded Accounting Principles Board (APB) Opinion 25, “Accounting
for Stock Issued to Employees.”
The
Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the
Company’s results of operations is discussed at Note 3.
The
Company adopted SFAS 154, “Accounting
Changes and Error Corrections,” in
the
first quarter of 2006. SFAS 154 requires retrospective application to financial
statements of prior periods for every voluntary change in accounting principle
unless such retrospective application is impracticable. SFAS 154 replaces APB
20, “Accounting
Changes,”
and SFAS
3, “Reporting
Accounting Changes in Interim Financial Statements.” The
adoption of SFAS 154 had no impact on the Company’s results of operations, cash
flows or financial position.
SFAS
157,
“Fair
Value Measurements,”
was
issued in September 2006. SFAS 157 establishes a framework for measuring
fair value to increase the consistency and comparability in fair value
measurements. The Company will adopt SFAS 157 in the first quarter of
2008, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows or financial
position.
In
September 2006, SFAS 158, “Employers'
Accounting for Defined Benefit Pension and Other Postretirement
Plans,”
amended SFAS 87 and SFAS 106 to require recognition of the overfunded or
underfunded status of pension and other postretirement benefit plans on the
balance sheet. Under SFAS 158, gains and losses, prior service costs and
credits, and any remaining transition amounts under SFAS 87 and SFAS 106 that
have not yet been recognized through net periodic benefit cost are to be
recognized in accumulated other comprehensive income, net of tax effects, until
they are amortized as a component of net periodic cost. The Company adopted
SFAS
158 as of December 31, 2006. Because a significant amount of the Company’s
pension and other postretirement costs recorded under SFAS 87 and SFAS 106
are
attributable to employees in its regulated operations, the adoption of SFAS
158
primarily resulted in the recording of additional regulatory assets. The impact
of adoption on the Company’s financial position is detailed at Note 3. The
adoption did not have an impact on the Company’s results of operations or cash
flows.
SFAS
159,
“The
Fair Value Option for Financial Assets and Financial
Liabilities,”
was
issued in February 2007. SFAS 159 allows entities to measure at fair value
many
financial instruments and certain other assets and liabilities that are not
otherwise required to be measured at fair value. SFAS 159 is effective for
fiscal years beginning after November 15, 2007. The Company has not determined
what impact, if any, that adoption will have on the Company’s results of
operations, cash flows or financial position.
FIN
48,
“Accounting
for Uncertainty in Income Taxes,” was
issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with SFAS
109,“Accounting
for Income Taxes.” FIN
48
prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of tax positions taken or expected to
be
taken in a tax return. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure and transition. The Company will adopt FIN 48 in the first quarter
of
2007, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows or financial
position.
FASB
Staff Position (FSP) AUG AIR-1 “Accounting
for Planned Major Maintenance Activities,”
was
issued in September 2006, and amends APB 28, “Interim
Financial Reporting,”
to
prohibit the use of the accrue-in-advance method of accounting for planned
major
maintenance in annual and interim financial reporting periods. As
disclosed in Note 1A, the Company has received specific SCPSC orders providing
for use of accrue-in-advance accounting for certain planned major maintenance
activities. Accordingly, the Company will follow SFAS 71 when accounting for
these activities. The Company will adopt FSP AUG AIR-1 in the first quarter
of
2007, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows or financial position.
The
United States Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin 108 (SAB 108) in September 2006. SAB 108 provides guidance on the
consideration of the effects of prior year misstatements in quantifying and
assessing the materiality of current year misstatements. SAB 108 also
provides transition guidance for correcting errors existing from prior
years. The Company adopted SAB 108 in December 2006. The adoption had no
impact on the Company’s results of operations, cash flows or financial
position.
N.
Earnings
Per Share
Earnings
per share amounts have been computed in accordance with SFAS 128,
“Earnings
Per Share.”
Under
SFAS 128, basic earnings per share are computed by dividing net income by
the weighted average number of common shares outstanding for the period. Diluted
earnings per share are computed by dividing net income by the weighted average
number of shares of common stock outstanding during the period, after giving
effect to securities considered to be dilutive potential common stock. The
Company uses the treasury stock method in determining total dilutive potential
common stock. The Company has no securities that would have an antidilutive
effect on earnings per share.
O.
Transactions
with Affiliates
SCE&G
holds equity-method investments in two partnerships involved in converting
coal
to synthetic fuel. SCE&G had recorded as receivables from these affiliated
companies approximately $31.8 million and $24.6 million at
December 31, 2006 and 2005, respectively. SCE&G had recorded as
payables to these affiliated companies approximately $26.6 million and
$25.3 million at December 31, 2006 and 2005, respectively. SCE&G
purchased approximately $291.1 million, $248.1 million and
$190.6 million of synthetic fuel from these affiliated companies in 2006,
2005 and 2004, respectively.
The
Company received cash distributions from equity investees of $6.7 million in
2006, $7.1 million in 2005 and $7.3 million in 2004. The Company made cash
investments in equity investees of $18.4 million in 2006, $17.7 million in
2005
and $18.7 million in 2004.
P.
Use
of Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
2.
RATE AND OTHER REGULATORY MATTERS
South
Carolina Electric & Gas Company
Electric
In
a
January 2005 order, the SCPSC granted SCE&G a composite increase in
retail electric rates of 2.89%, designed to produce additional annual revenues
of $41.4 million based on a test year calculation. The SCPSC lowered
SCE&G's allowed return on common equity from 12.45% to an amount not to
exceed 11.4%, with rates set at 10.7%. The new rates became effective in
January 2005. As part of its order, the SCPSC approved SCE&G's recovery
of construction and operating costs for SCE&G's new Jasper County Electric
Generating Station, recovery of costs of mandatory environmental upgrades
primarily related to Federal Clean Air Act regulations and, beginning in January
2005, the application of current and anticipated net synthetic fuel tax credits
to offset the cost of constructing the back-up dam at Lake Murray. Under the
accounting methodology approved by the SCPSC, construction costs related to
the
Lake Murray back-up dam project were recorded in a special dam remediation
account outside of rate base, and depreciation is being recognized against
the
balance in this account on an accelerated basis, subject to the availability
of
the synthetic fuel tax credits.
In
the
January 2005 order, the SCPSC also approved recovery over a five-year period
of
SCE&G's approximately $14 million of costs incurred in the formation of the
GridSouth Regional Transmission Organization and recovery through base rates
over three years of $25.6 million of purchased power costs that were
previously deferred. As a part of its order, the SCPSC extended through 2010
its
approval of the accelerated capital recovery plan for SCE&G's Cope
Generating Station. Under the plan, in the event that SCE&G would otherwise
earn in excess of its maximum allowed return on common equity, SCE&G may
increase depreciation of its Cope Generating Station up to $36 million
annually without additional approval of the SCPSC. Any unused portion of the
$36
million in any given year may be carried forward for possible use in the
immediately following year. No such additional depreciation was recognized
in 2006, 2005 or 2004.
SCE&G's
rates are established using a cost of fuel component approved by the SCPSC
which
may be modified periodically to reflect changes in the price of fuel purchased
by SCE&G. SCE&G's cost of fuel component in effect during 2006 and 2005
was as follows:
|
Rate Per KWh
|
Effective Date
|
|
$.01764
|
January-April
2005
|
|
$.02256
|
May
2005-April 2006
|
|
$.02516
|
May-December
2006
|
In
connection with the May 2006 fuel component increase, SCE&G agreed to spread
the recovery of previously undercollected fuel costs of $38.5 million over
a
two-year period.
Gas
In
October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million,
or 5.69%, in retail gas base rates. The new rates are based on an allowed return
on common equity of 10.25%, and became effective with the first billing cycle
in
November 2005.
In
June
2006, SCE&G reported to the SCPSC that its return on common equity for the
twelve months ended March 31, 2006 was more than 0.5% below the allowed return,
and as provided under South Carolina’s Natural Gas Rate Stabilization Act,
SCE&G requested an annualized increase in certain natural gas base rates. In
September 2006, the SCPSC approved an annual increase of $17.4 million. The
rate
adjustment was effective with the first billing cycle in November
2006.
SCE&G's
rates are established using a cost of gas component approved by the SCPSC which
may be modified periodically to reflect changes in the price of natural gas
purchased by SCE&G. SCE&G's cost of gas components by class were as
follows (rate per therm):
|
Effective
Date
|
|
Residential
|
|
Small/Medium
|
|
Large
|
|
|||
|
January-October
2005
|
|
$.903
|
|
$.903
|
|
$.903
|
|
|||
|
November
2005
|
|
|
1.297
|
|
|
1.222
|
|
|
1.198
|
|
|
December
2005
|
|
|
1.362
|
|
|
1.286
|
|
|
1.263
|
|
|
January
2006
|
|
|
1.297
|
|
|
1.222
|
|
|
1.198
|
|
|
February-October
2006
|
|
|
1.227
|
|
|
1.152
|
|
|
1.128
|
|
|
November
2006
|
1.115
|
1.004
|
.963
|
|||||||
|
December
2006
|
1.240
|
1.130
|
1.090
|
|||||||
In
October 2006, the SCPSC approved a reduction in the cost of gas component of
SCE&G’s retail natural gas rates, effective with the first billing cycle of
November 2006. The SCPSC also authorized SCE&G to adjust its cost of gas on
a monthly, rather than an annual, basis beginning in December 2006.
Prior
to
November 2005, the SCPSC allowed SCE&G to recover through a billing
surcharge to its gas customers the costs of environmental cleanup at the sites
of former MGPs. Effective with the first billing cycle of November 2005, the
billing surcharge was eliminated. In its place, SCE&G defers certain MGP
environmental costs in regulatory asset accounts and collects and amortizes
these costs through base rates.
Public
Service Company of North Carolina, Incorporated (PSNC Energy)
PSNC
Energy’s rates are established using a benchmark cost of gas approved by the
NCUC, which may be modified periodically to reflect changes in the market price
of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary
to
track these changes and accounts for any over- or under-collections of the
delivered cost of gas in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC Energy’s gas purchasing practices
annually.
PSNC
Energy’s benchmark cost of gas was as follows:
|
Rate
Per Therm
|
Effective
Date
|
|
$.825
|
January
2005
|
|
.725
|
February-July
2005
|
|
.825
|
August-September
2005
|
|
1.100
|
October
2005
|
|
1.275
|
November-December
2005
|
|
1.075
|
January
2006
|
|
.875
|
February
2006
|
|
.825
|
March-December
2006
|
In
January 2007, the NCUC approved PSNC Energy’s request to decease the benchmark
cost of gas from $0.825 per therm to $0.750 per therm for service rendered
on
and after January 1, 2007.
In
October 2006, the NCUC granted PSNC Energy an annual increase in retail natural
gas margin revenues of approximately $15.2 million, or 2.6%, which was offset
by
a $9.2 million decrease in fixed-gas cost revenues, for an overall increase
of
$6 million, or 1.0%. The new rates are based on an allowed overall rate of
return of 8.9%, and became effective with the first billing cycle in November
2006. In connection with the rate increase, the NCUC approved PSNC Energy’s
recovery through rates, over a three-year period, of certain costs for
environmental remediation and pipeline integrity management.
In
September 2006, in connection with PSNC Energy’s 2006 Annual Prudence Review,
the NCUC determined that PSNC Energy’s gas costs, including all hedging
transactions, were reasonable and prudently incurred during the twelve-month
review ended March 31, 2006.
In
March
2006, the NCUC authorized PSNC Energy to place pipeline supplier refunds that
it
presently holds and future supplier refunds into the appropriate deferred
accounts for the over- or under-recovery of gas costs. Prior to this
authorization, refunds from PSNC Energy’s interstate pipeline transporters were
placed in a state-approved expansion fund to provide financing for expansion
into areas that otherwise would not be economically feasible to serve. In
December 2006, PSNC Energy received a disbursement of $1.1 million from the
state expansion fund upon completion of a project to expand natural gas service
to Louisburg, North Carolina.
In
November 2005, the NCUC authorized an amendment to PSNC Energy’s Rider D rate
mechanism allowing recovery of certain uncollectible expenses related to gas
cost. This change was effective December 1, 2005.
Carolina
Gas Transmission Corporation
In
July
2006, FERC approved the application for merger of SCG Pipeline, Inc., into
SCPC.
SCPC was renamed CGTC. The merger was finalized and CGTC commenced operations
as
an open access transportation-only interstate pipeline company on November
1,
2006.
3. EMPLOYEE
BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension
and Other Postretirement Benefit Plans
The
Company sponsors a noncontributory defined benefit pension plan, covering
substantially all permanent employees. The Company's policy has been to fund
the
plan to the extent permitted by applicable federal income tax regulations as
determined by an independent actuary.
Effective
July 1, 2000 the Company's pension plan, which provided a final average pay
formula, was amended to provide a cash balance formula for employees hired
before January 1, 2000 who elected that option and for all employees hired
on or
after January 1, 2000. For employees who elected to remain under the final
average pay formula, benefits are based on years of credited service and the
employee's average annual base earnings received during the last three years
of
employment. For employees under the cash balance formula, benefits accumulate
as
a result of compensation credits and interest credits.
In
addition to pension benefits, the Company provides certain unfunded
postretirement health care and life insurance benefits to active and retired
employees. Retirees share in a portion of their medical care cost. The Company
provides life insurance benefits to retirees at no charge. The costs of
postretirement benefits other than pensions are accrued during the years the
employees render the services necessary to be eligible for these
benefits.
The
Company adopted the balance sheet recognition provisions of SFAS 158 at December
31, 2006. The incremental effect of applying SFAS 158 on individual line items
in the balance sheet was as follows:
|
Before
|
After
|
|||||||||
|
Application
of
|
Application
of
|
|||||||||
|
December
31, 2006
|
SFAS
158
|
Adjustments
|
SFAS
158
|
|||||||
|
Millions
of dollars
|
||||||||||
|
Deferred
debits - pension asset, net
|
$
|
316.7
|
$
|
(117.2
|
)
|
$
|
199.5
|
|||
|
Deferred
debits - regulatory assets
|
649.9
|
142.4
|
792.3
|
|||||||
|
Deferred
debits - other
|
137.9
|
1.6
|
139.5
|
|||||||
|
Total
deferred debits
|
1,131.2
|
26.8
|
1,158.0
|
|||||||
|
Total
assets
|
9,790.2
|
26.8
|
9,817.0
|
|||||||
|
Common
equity
|
2,855.8
|
(9.8
|
)
|
2,846.0
|
||||||
|
Total
shareholders’ investment
|
2,962.0
|
(9.8
|
)
|
2,952.2
|
||||||
|
Total
capitalization
|
6,036.5
|
(9.8
|
)
|
6,026.7
|
||||||
|
Current
liabilities - other
|
112.2
|
13.7
|
125.9
|
|||||||
|
Total
current liabilities
|
1,391.5
|
13.7
|
1,405.2
|
|||||||
|
Deferred
credits - deferred income taxes, net
|
953.1
|
(6.4
|
)
|
946.7
|
||||||
|
Deferred
credits - postretirement benefits
|
158.2
|
35.8
|
194.0
|
|||||||
|
Deferred
credits - other
|
124.8
|
(6.5
|
)
|
118.3
|
||||||
|
Total
deferred credits
|
2,362.1
|
22.9
|
2,385.0
|
|||||||
|
Total
capitalization and liabilities
|
9,790.2
|
26.8
|
9,817.0
|
|||||||
Funded
Status
The
funded status at the end of the year and the related amounts recognized on
the
balance sheets follow:
|
Pension
Benefits
|
Other
Postretirement Benefits
|
||||||||||||
|
December
31,
|
December
31,
|
||||||||||||
|
2006
|
2005
|
2006
|
2005
|
||||||||||
|
Millions
of Dollars
|
|||||||||||||
|
Fair
value of plan assets
|
$
|
912.5
|
$
|
854.3
|
-
|
-
|
|||||||
|
Benefit
obligations
|
713.0
|
711.4
|
$
|
206.9
|
$
|
202.1
|
|||||||
|
Funded
status
|
199.5
|
142.9
|
(206.9
|
)
|
(202.1
|
)
|
|||||||
|
Unrecognized
net actuarial loss
|
n/a
|
88.4
|
n/a
|
44.4
|
|||||||||
|
Unrecognized
prior service cost
|
n/a
|
71.3
|
n/a
|
5.2
|
|||||||||
|
Unrecognized
transition obligation
|
n/a
|
0.6
|
n/a
|
4.3
|
|||||||||
|
Amount
recognized, end of year
|
$
|
199.5
|
$
|
303.2
|
$
|
(206.9
|
)
|
$
|
(148.2
|
)
|
|||
Amounts
recognized on the balance sheets consist of:
|
Noncurrent
asset
|
$
|
199.5
|
n/a
|
-
|
n/a
|
||||||||
|
Current
liability
|
-
|
n/a
|
$
|
(12.9
|
)
|
n/a
|
|||||||
|
Noncurrent
liability
|
-
|
n/a
|
(194.0
|
)
|
n/a
|
||||||||
|
Prepaid
benefit cost
|
n/a
|
$
|
303.2
|
n/a
|
n/a
|
||||||||
|
Accrued
benefit cost
|
n/a
|
-
|
n/a
|
$
|
(148.2
|
)
|
Deferred
amounts recognized in accumulated other comprehensive income, which is a
component of common equity, as of December 31, 2006, including the adjustment
above to reflect the adoption of SFAS 158, were as follows:
|
December
31, 2006
|
Pension
Benefits
|
Other
Postretirement
Benefits
|
Total
|
|||||||
|
Millions
of dollars
|
||||||||||
|
Transition
Obligation
|
-
|
$
|
0.6
|
$
|
0.6
|
|||||
|
Prior
Service Costs
|
$
|
0.9
|
0.6
|
1.5
|
||||||
|
Actuarial
Losses
|
6.6
|
2.4
|
9.0
|
|||||||
|
Total
|
$
|
7.5
|
$
|
3.6
|
$
|
11.1
|
||||
The
estimated transition obligation, prior service costs and actuarial losses for
the defined benefit plans that will be amortized from accumulated other
comprehensive income into net periodic benefit costs during 2007 are less than
$300,000 in aggregate.
Changes
in Benefit Obligations
The
measurement date used to determine pension and other postretirement benefit
obligations is December 31. Data related to the changes in the projected
benefit obligation for retirement benefits and the accumulated benefit
obligation for other postretirement benefits are presented below.
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||
|
|
|
2006
|
2005
|
2006
|
2005
|
|
|||||||
|
|
|
Millions
of dollars
|
|
||||||||||
|
Benefit
obligation, January 1
|
|
$
|
711.5
|
|
$
|
669.5
|
|
$
|
202.1
|
|
$
|
197.5
|
|
|
Service
cost
|
|
|
14.0
|
|
|
12.2
|
|
|
4.6
|
|
|
3.5
|
|
|
Interest
cost
|
|
|
39.8
|
|
|
38.3
|
|
|
11.5
|
|
|
10.7
|
|
|
Plan
participants' contributions
|
|
|
-
|
|
|
-
|
|
|
2.1
|
|
|
2.3
|
|
|
Plan
amendments
|
|
|
0.6
|
|
|
-
|
|
|
4.0
|
|
(0.3
|
)
|
|
|
Actuarial
(gain) loss
|
|
|
(14.4
|
)
|
|
27.1
|
|
|
(5.5
|
)
|
|
1.5
|
|
|
Benefits
paid
|
|
|
(38.5
|
)
|
|
(35.6
|
)
|
|
(11.9
|
)
|
|
(13.1
|
)
|
|
Benefit
obligation, December 31
|
|
$
|
713.0
|
|
$
|
711.5
|
|
$
|
206.9
|
|
$
|
202.1
|
|
The
accumulated benefit obligation for retirement benefits at the end of 2006 and
2005 was $666.6 million and $664.4 million, respectively. These accumulated
retirement benefit obligations differ from the projected retirement benefit
obligations above in that they reflect no assumptions about future compensation
levels.
Significant
assumptions used to determine the above benefit obligations are as
follows:
|
|
|
2006
|
2005
|
|
|||
|
Annual
discount rate used to determine benefit obligations
|
|
|
5.85
|
%
|
5.60
|
%
|
|
|
Assumed
annual rate of future salary increases for projected benefit
obligation
|
|
|
4.00
|
%
|
4.00
|
%
|
|
A
9.5%
annual rate of increase in the per capita cost of covered health care benefits
was assumed for 2006. The rate was assumed to decrease gradually to 5.0% for
2013 and to remain at that level thereafter. The effects of a one percentage
point increase or decrease in the annual rate on accumulated other
postretirement benefit obligation for health care benefits are as
follows:
|
|
|
1%
Increase
|
1%
Decrease
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Effect
on postretirement benefit obligation
|
|
$
|
3.1
|
$
|
(2.7
|
)
|
|
Changes
in Plan Assets
|
|
|
Retirement
Benefits
|
|
||||
|
|
|
2006
|
2005
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Fair
value of plan assets, January 1
|
|
$
|
854.3
|
$
|
846.7
|
|
|
|
Actual
return on plan assets
|
|
|
96.7
|
|
43.2
|
|
|
|
Benefits
paid
|
|
|
(38.5
|
)
|
|
(35.6
|
)
|
|
Fair
value of plan assets, December 31
|
|
$
|
912.5
|
$
|
854.3
|
|
|
The
Company determines the fair value of substantially all of its pension assets
utilizing market quotes rather than utilizing any calculated values, “market
related” values or other modeling techniques. At the end of 2006 and 2005, the
fair value of plan assets for the pension plan exceeded both the projected
benefit obligation and the accumulated benefit obligation discussed above.
In
connection with the joint ownership of Summer Station, as of December 31,
2006 and 2005, the Company recorded within deferred credits a $3.6 million
and $10.2 million obligation, respectively, to Santee Cooper, representing
an estimate of the net pension asset attributable to the Company's contributions
to the pension plan that were recovered through billings to Santee Cooper for
its one-third portion of shared costs. As of December 31, 2006 and 2005,
the Company also recorded within deferred debits a $9.9 million and
$7.1 million receivable, respectively, from Santee Cooper, representing an
estimate of its portion of the unfunded net postretirement benefit
obligation.
Expected
Cash Flows
The
total
benefits expected to be paid from the pension plan or from the Company's assets
for the other postretirement benefits plan, respectively, are as
follows:
|
|
Other
Postretirement Benefits*
|
|||||||||
|
Expected
Benefit Payments
|
Pension Benefits
|
Excluding
Medicare Subsidy
|
Including
Medicare Subsidy
|
|||||||
|
|
Millions
of dollars
|
|||||||||
|
|
|
|
|
|||||||
|
2007
|
$
|
39.7
|
$
|
13.3
|
$
|
12.9
|
||||
|
2008
|
40.1
|
13.6
|
13.2
|
|||||||
|
2009
|
40.5
|
13.6
|
13.2
|
|||||||
|
2010
|
40.9
|
14.1
|
13.7
|
|||||||
|
2011
|
41.3
|
14.3
|
13.9
|
|||||||
|
2012-2016
|
212.8
|
76.2
|
74.2
|
|||||||
*
Net of
participant contributions
Net
Periodic Cost
As
allowed by SFAS 87 and SFAS 106, as amended, the Company records net
periodic benefit cost (income) utilizing beginning of the year assumptions.
Disclosures required for these plans under SFAS 132, “Employer's
Disclosures about Pensions and Other Postretirement Benefits”
as
amended, are set forth in the following tables.
Components
of Net Periodic Benefit Cost (Income)
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||||||||
|
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|
|||||||||||
|
|
|
Millions
of dollars
|
|
||||||||||||||||
|
Service
cost
|
|
$
|
14.0
|
$
|
12.2
|
|
$
|
11.1
|
|
$
|
4.6
|
$
|
3.5
|
|
$
|
3.3
|
|
||
|
Interest
cost
|
|
|
39.8
|
38.3
|
|
|
37.4
|
|
|
11.5
|
10.7
|
|
|
11.4
|
|
||||
|
Expected
return on assets
|
|
|
(75.2
|
)
|
(76.3
|
)
|
|
(71.0
|
)
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|||
|
Prior
service cost amortization
|
|
|
6.8
|
6.9
|
|
|
6.6
|
|
|
1.1
|
0.8
|
|
|
1.4
|
|
||||
|
Amortization
of actuarial loss
|
|
|
0.5
|
-
|
|
|
-
|
|
|
1.7
|
1.2
|
|
|
1.9
|
|
||||
|
Transition
amount amortization
|
|
|
0.6
|
0.8
|
|
|
0.8
|
|
|
0.8
|
0.8
|
|
|
0.8
|
|
||||
|
Net
periodic benefit (income) cost
|
|
$
|
(13.5
|
)
|
$
|
(18.1
|
)
|
$
|
(15.1
|
)
|
$
|
19.7
|
$
|
17.0
|
|
$
|
18.8
|
|
|
Significant
Assumptions Used in Determining Net Periodic Benefit Cost
(Income)
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||||||||
|
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|
|||||||||||
|
Discount
rate
|
|
|
5.60
|
%
|
5.75
|
%
|
6.00
|
%
|
5.60
|
%
|
5.75
|
%
|
6.00
|
%
|
|||||
|
Expected
return on plan assets
|
|
|
9.00
|
%
|
9.25
|
%
|
9.25
|
%
|
n/a
|
n/a
|
n/a
|
||||||||
|
Rate
of compensation increase
|
|
|
4.00
|
%
|
4.00
|
%
|
4.00
|
%
|
4.00
|
%
|
4.00
|
%
|
4.00
|
%
|
|||||
|
Health
care cost trend rate
|
|
|
n/a
|
n/a
|
n/a
|
9.00
|
%
|
9.00
|
%
|
9.50
|
%
|
||||||||
|
Ultimate
health care cost trend rate
|
|
|
n/a
|
n/a
|
n/a
|
5.00
|
%
|
5.00
|
%
|
5.00
|
%
|
||||||||
|
Year
achieved
|
|
|
n/a
|
n/a
|
n/a
|
2012
|
2011
|
2011
|
|||||||||||
The
effect of a one-percentage-point increase or decrease in the assumed health
care
cost trend rate on total service and interest cost is less than
$250,000.
Pension
Plan Contributions
The
pension trust is adequately funded. No contributions have been required since
1997, and the Company does not anticipate making contributions to the pension
plan until after 2010.
Pension
Plan Asset Allocations
The
Company's pension plan asset allocation at December 31, 2006 and 2005 and
the target allocations for 2007 are as follows:
|
|
|
Target
Allocation
|
Percentage of Plan Assets
At
December 31,
|
|
||||||
|
Asset
Category
|
|
2007
|
2006
|
2005
|
|
|||||
|
Equity
Securities
|
|
|
70
|
%
|
|
72
|
%
|
|
72
|
%
|
|
Debt
Securities
|
|
|
30
|
%
|
|
28
|
%
|
|
28
|
%
|
The
assets of the pension plan are invested in accordance with the objectives of
(1) fully funding the actuarial accrued liability for the pension plan,
(2) maximizing return within reasonable and prudent levels of risk in order
to minimize contributions, and (3) maintaining sufficient liquidity to meet
benefit payment obligations on a timely basis. The pension plan operates with
several risk and control procedures, including ongoing reviews of liabilities,
investment objectives, investment managers and performance expectations.
Transactions involving certain types of investments are prohibited. Equity
securities held by the pension plan during the above periods did not include
SCANA common stock.
In
developing the expected long-term rate of return assumptions, management
evaluates the pension plan's historical cumulative actual returns over several
periods, all of which returns have been in excess of related broad indices.
The
expected long-term rate of return of 9.0% assumes an asset allocation of 70%
with equity managers and 30% with fixed income managers. Management regularly
reviews such allocations and periodically rebalances the portfolio when
considered appropriate. For 2007, the expected rate of return also will be
9.0%.
Share-Based
Compensation
The
SCANA
Corporation Long-Term Equity Compensation Plan provides for grants of incentive
nonqualified stock options, stock appreciation rights, restricted stock,
performance shares and performance units to certain key employees and
non-employee directors. The plan currently authorizes the issuance of up to
five
million shares of the Company’s common stock, no more than one million of which
may be granted in the form of restricted stock.
SFAS
123
(revised 2004), “Share-Based
Payment”
(SFAS
123(R)), requires compensation costs related to share-based payment transactions
to be recognized in the financial statements. With limited exceptions,
compensation cost is measured based on the grant-date fair value of the
instruments issued and is recognized over the period that an employee provides
service in exchange for the award. The cumulative effect of the adoption of
SFAS
123(R) on January 1, 2006 resulted in a $.05 per share (net of tax) gain in
the
first quarter of 2006 based on a reduction of prior compensation accruals for
performance awards (discussed below) granted in 2004 and 2005.
Liability
Awards
Through
2006, certain executives were granted a target number of performance shares
on
an annual basis that vest over a three-year period. Each performance share
has a
value that is equal to, and changes with, the value of a share of SCANA common
stock, and dividend equivalents are accrued on, and reinvested in, the
performance shares. Payout of performance share awards is determined by SCANA's
performance against pre-determined measures of total shareholder return (TSR)
as
compared to a peer group of utilities (weighted 60%) and growth in earnings
per
share (as defined) (weighted 40%) over the three year plan cycle. TSR is
calculated by dividing stock price change over the three-year period, plus
cash
dividends, by the stock price as of the beginning of the period. Payouts vary
according to SCANA's ranking against the peer group and relative earnings per
share projection achievement. Awards are designated as target shares of SCANA
common stock and may be paid in stock or cash or a combination of stock and
cash
at SCANA's discretion.
Under
SFAS 123(R) compensation cost of these liability awards is recognized over
the
three-year performance period based on the estimated fair value of the award,
which is periodically updated based on expected ultimate cash payout, and is
reduced by estimated forfeitures. Cash-settled liabilities totaling $6.4 million
were paid during the twelve months ended December 31, 2006. No such payments
were made in 2005.
Fair
value adjustments for performance awards resulted in a reduction to compensation
expense recognized in the statements of income, exclusive of the cumulative
effect adjustment discussed previously, totaling $(6.5) million for the year
ended December 31, 2006, and increases to compensation expense totaling $3.6
million and $13.0 million for the years ended December 31, 2005 and 2004,
respectively. Fair value adjustments resulted in a net credit to capitalized
compensation cost of approximately $(0.8) million during the year ended December
31, 2006, compared to capitalized costs of approximately $0.4 million in 2005
and $1.4 million in 2004.
Equity
Awards
A
summary
of activity related to nonqualified stock options since December 31, 2003
follows:
|
|
Number
of
Options
|
Weighted
Average
Exercise Price
|
|||||
|
Outstanding-December
31, 2003
|
1,493,685
|
$
|
27.39
|
||||
|
Exercised
|
(751,997
|
)
|
$
|
26.28
|
|||
|
Forfeited
|
(11,241
|
)
|
$
|
27.52
|
|||
|
Outstanding-December
31, 2004
|
730,447
|
$
|
27.49
|
||||
|
Exercised
|
(291,177
|
)
|
$
|
27.48
|
|||
|
Forfeited
|
-
|
-
|
|||||
|
Outstanding-
December 31, 2005
|
439,270
|
$
|
27.53
|
||||
|
Exercised
|
(53,330
|
)
|
$
|
27.52
|
|||
|
Forfeited
|
-
|
-
|
|||||
|
Outstanding-
December 31, 2006
|
385,940
|
$
|
27.56
|
||||
No
stock
options have been granted since August 2002, and all options were fully vested
in August 2005. The options expire ten years after the grant date. At December
31, 2006, all outstanding options were currently exercisable at prices ranging
from $25.50-$29.60, and had a weighted-average remaining contractual life of
4.9
years.
All
options were granted with exercise prices equal to the fair market value of
SCANA’s common stock on the respective grant dates; therefore, no compensation
expense was recognized in connection with such grants. If the Company had
recognized compensation expense for the issuance of options based on the fair
value method described in SFAS 123(R), pro forma net income and earnings per
share would have been unchanged from that reported for the twelve months ended
December 31, 2005 and 2004.
The
exercise of stock options during the period was satisfied using original issue
shares of the Company’s common stock. The Company realized $1.5 million, $8.0
million and $20.5 million in cash upon the exercise of options in the twelve
months ended December 31, 2006, 2005 and 2004, respectively. In addition, tax
benefits resulting from the exercise of those stock options totaling $0.3
million, $1.3 million and $2.4 million were credited to additional paid in
capital in these periods.
Beginning
in 2007, the Company will satisfy the exercise of stock options using open
market purchases of common stock. The Company estimates that 200,000 common
shares will be repurchased in 2007 due to the exercise of stock
options.
4. LONG-TERM
DEBT
Long-term
debt by type with related weighted average interest rates and maturities is
as
follows:
|
|
December
31,
|
||||||||||||
|
|
Weighted-Average
Interest
Rate
|
Maturity
Date
|
2006
|
2005
|
|||||||||
|
|
Millions
of dollars
|
||||||||||||
|
Medium-Term
Notes (unsecured)(a)
|
6.40
|
%
|
2007-2012
|
$
|
940
|
$
|
940
|
||||||
|
First
Mortgage Bonds (secured)
|
6.00
|
%
|
2009-2036
|
1,675
|
1,550
|
||||||||
|
First
& Refunding Mortgage Bonds (secured)
|
9.00
|
%
|
2006
|
-
|
131
|
||||||||
|
GENCO
Notes (secured)
|
5.92
|
%
|
2011-2024
|
123
|
127
|
||||||||
|
Industrial
and Pollution Control Bonds
|
5.24
|
%
|
2012-2032
|
156
|
156
|
||||||||
|
Senior
Debentures(b)
|
7.47
|
%
|
2012-2026
|
119
|
122
|
||||||||
|
Fair
value of interest rate swaps(c)
|
21
|
25
|
|||||||||||
|
Other
|
2007-2014
|
89
|
107
|
||||||||||
|
Total
debt
|
3,123
|
3,158
|
|||||||||||
|
Current
maturities of long-term debt
|
(43
|
)
|
(188
|
)
|
|||||||||
|
Unamortized
Discount
|
(13
|
)
|
(22
|
)
|
|||||||||
|
Total
long-term debt, net
|
$
|
3,067
|
$
|
2,948
|
|||||||||
(a)
In
2006, includes $100.0 million of variable interest debt and
$25.0 million of fixed rate debt hedged by a variable
interest rate
swap.
(b)
In
2006, includes $19.2 million of fixed rate debt hedged by variable interest
rate swaps.
(c)
In
2006, includes $20.7 million representing unamortized payments received to
terminate previous swaps. See
discussion at
Note 9.
The
annual amounts of long-term debt maturities for the years 2007 through 2011
are
summarized as follows:
|
Year
|
|
Millions
of
dollars
|
|
|
|
|
|
|
||
|
2007
|
|
$
|
43
|
|
|
2008
|
|
|
232
|
|
|
2009
|
|
|
143
|
|
|
2010
|
|
|
21
|
|
|
2011
|
|
|
625
|
|
Under
an
agreement with the South Carolina Transportation Infrastructure Bank (the Bank)
and the South Carolina Department of Transportation (SCDOT), SCE&G borrowed
an aggregate $59 million from the Bank to construct a roadbed for SCDOT in
connection with the Lake Murray back-up dam project. Such borrowings are being
repaid interest-free over ten years. At December 31, 2006 and 2005,
SCE&G had $44.3 million and $50.2 million outstanding under the
agreement, respectively.
Substantially
all of SCE&G's and GENCO's electric utility plant is pledged as collateral
in connection with long-term debt. The Company is in compliance with all debt
covenants.
5. LINES
OF CREDIT AND SHORT-TERM BORROWINGS
Details
of lines of credit at December 31, 2006 and 2005, are as
follows:
|
|
|
2006
|
2005
|
|
||||
|
|
|
Millions
of dollars
|
|
|||||
|
Lines
of credit (total and unused)
|
|
|
|
|
|
|||
|
Committed:
|
|
|
|
|
|
|
|
|
|
Short-term
|
|
$
|
-
|
$
|
350
|
|
||
|
Long-term
|
|
|
1,100
|
|
650
|
|
||
|
Uncommitted
(a)
|
|
|
103
|
|
103
|
|||
|
(a)
SCANA or SCE&G may use $78 million of these lines of
credit.
|
||||||||
Bank
loans and commercial paper outstanding (270 or fewer days) at December 31,
2006
and 2005 were as follows:
|
Millions
of dollars
|
2006
|
2005
|
|||||
|
Amount
|
Weighted
Average
Interest
Rate
|
Amount
|
Weighted
Average
Interest
Rate
|
||||
|
SCANA
|
$
|
-
|
-
|
$
|
25
|
4.43%
|
|
|
SCE&G
|
238
|
5.38%
|
196
|
4.40%
|
|||
|
Fuel
Company
|
124
|
5.38%
|
107
|
4.39%
|
|||
|
PSNC
Energy
|
125
|
5.40%
|
99
|
4.47%
|
|||
|
Total
|
$
|
487
|
5.38%
|
$
|
427
|
4.42%
|
|
The
Company pays fees to banks as compensation for maintaining committed lines
of
credit.
Nuclear
and fossil fuel inventories and emission allowances are financed through the
issuance by Fuel Company of short-term commercial paper. All commercial paper
borrowings are supported by five-year revolving credit facilities which expire
on December 19, 2011. SCANA also has a five-year revolving credit facility
which
expires December 19, 2011.
6. COMMON
EQUITY
SCANA
Corporation's Restated Articles of Incorporation do not limit the dividends
that
may be paid on its common stock. However, the Restated Articles of Incorporation
of SCE&G contain provisions that, under certain circumstances, which the
Company considers to be remote, could limit the payment of cash dividends on
its
common stock.
With
respect to hydroelectric projects, the Federal Power Act requires the
appropriation of a portion of certain earnings therefrom. At December 31,
2006, approximately $54 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common
stock.
Cash
dividends on common stock were declared during 2006, 2005 and 2004 at an annual
rate per share of $1.68, $1.56 and $1.46, respectively.
The
accumulated balances related to each component of other comprehensive income
(loss) were as follows:
|
|
|
|
Unrealized
Gains
(Losses)
on Securities
|
Cash
Flow Hedging Activities
|
Minimum
Pension Liability Adjustment
|
Deferred
Costs of Employee
Benefit
Plans
|
Accumulated
Other
Comprehensive
Income
(Loss)
|
|
||||||||
|
|
Millions
of dollars
|
|
|
|
||||||||||||
|
Balance,
December 31, 2003
|
$
|
2
|
$
|
4
|
|
$
|
-
|
|
$
|
-
|
|
$
|
6
|
|
||
|
Other
comprehensive loss
|
|
(2
|
)
|
|
(8
|
)
|
|
-
|
|
|
-
|
|
|
(10
|
)
|
|
|
Balance,
December 31, 2004
|
|
-
|
|
(4
|
)
|
|
-
|
|
|
-
|
|
|
(4
|
)
|
||
|
Other
comprehensive income (loss)
|
|
-
|
|
1
|
|
|
(1
|
)
|
-
|
|
-
|
|||||
|
Balance,
December 31, 2005
|
-
|
(3
|
)
|
(1
|
)
|
-
|
(4
|
)
|
||||||||
|
Other
comprehensive income (loss)
|
-
|
(15
|
)
|
1
|
(11
|
)
|
(25
|
)
|
||||||||
|
Balance,
December 31, 2006
|
$
|
-
|
$
|
(18
|
)
|
$
|
-
|
$
|
(11
|
)
|
$
|
(29
|
)
|
|||
During
2006 and 2005, no unrealized gains or losses on securities were reclassified
into net income. The Company recognized a loss of $27.6 million, net of tax,
and
a gain of $4.0 million, net of tax, as a result of qualifying cash flow hedges
whose hedged transactions occurred during the years ended December 31, 2006
and
2005, respectively. As described in Notes 1 and 3, the Company adopted SFAS
158
at December 31, 2006 and recorded in accumulated other comprehensive income
gains, losses, prior service costs and credits that have not yet been recognized
through net periodic benefit cost, net of tax effects.
During
2004, $0.7 million was reclassified from unrealized gains and
$12.5 million was reclassified from unrealized losses on securities into
net income as a result of the sale of the Company's investments in ITC^DeltaCom,
Inc. (ITC^DeltaCom) and the impairment and subsequent sale of the Company's
investment in Knology, Inc. (Knology). The Company also recognized a gain of
$6.4 million, net of taxes, as a result of qualifying cash flow hedges
whose hedged transactions occurred during the year ended December 31,
2004.
7. PREFERRED
STOCK
Retirements
under sinking fund requirements are at par values. The aggregate of the annual
amounts of purchase or sinking fund requirements for preferred stock for the
years 2007 through 2011 is $2.5 million. The call premium of the respective
series of preferred stock in no case exceeds the amount of the annual dividend.
At December 31, 2006 SCE&G had shares of preferred stock authorized and
available for issuance as follows:
|
Par
Value
|
Authorized
|
Available
for Issuance
|
|
$100
|
1,000,000
|
-
|
|
$
50
|
592,405
|
300,000
|
|
$
25
|
2,000,000
|
2,000,000
|
Preferred
Stock (Not subject to purchase or sinking funds)
For
each
of the three years ended December 31, 2006, SCE&G had outstanding
1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par
Cumulative Preferred Stock (not subject to purchase or sinking
funds).
Preferred
Stock (Subject to purchase or sinking funds)
Changes
in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2006,
2005 and 2004 are summarized as follows:
|
|
Series
|
||||||||||||
|
|
4.50%,
4.60% (A)
&
5.125%
|
4.60%
(B)
&
6.00%
|
Total
Shares
|
Millions
of Dollars
|
|||||||||
|
Redemption
Price
|
$51.00
|
$50.50
|
|||||||||||
|
Balance
at December 31, 2003
|
81,034
|
112,561
|
193,595
|
$
|
9.7
|
||||||||
|
Shares
Redeemed-$50 par value
|
(2,516
|
)
|
(6,600
|
)
|
(9,116
|
)
|
(0.5
|
)
|
|||||
|
Balance
at December 31, 2004
|
78,518
|
105,961
|
184,479
|
9.2
|
|||||||||
|
Shares
Redeemed-$50 par value
|
(1,475
|
)
|
(6,600
|
)
|
(8,075
|
)
|
(0.4
|
)
|
|||||
|
Balance
at December 31, 2005
|
77,043
|
99,361
|
176,404
|
8.8
|
|||||||||
|
Shares
Redeemed-$50 par value
|
(2,608
|
)
|
(6,600
|
)
|
(9,208
|
)
|
(0.5
|
)
|
|||||
|
Balance
at December 31, 2006
|
74,435
|
92,761
|
167,196
|
$
|
8.3
|
||||||||
8. INCOME
TAXES
Total
income tax expense (benefit) attributable to income (before cumulative effect
of
accounting change) for 2006, 2005 and 2004 is as follows:
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
|
|
Millions
of dollars
|
|
|||||||
|
Current
taxes:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
$
|
93.9
|
$
|
10.2
|
|
$
|
(6.4
|
)
|
|
|
State
|
|
|
9.8
|
11.1
|
|
|
(5.2
|
)
|
||
|
Total
current taxes
|
|
|
103.7
|
21.3
|
|
(11.6
|
)
|
|||
|
Deferred
taxes, net:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
|
11.7
|
1.7
|
|
|
84.5
|
|
||
|
State
|
|
|
5.3
|
(6.9
|
)
|
|
5.4
|
|
||
|
Total
deferred taxes
|
|
|
17.0
|
(5.2
|
)
|
|
89.9
|
|
||
|
Investment
tax credits:
|
|
|
|
|
|
|
|
|||
|
Deferred-state
|
|
|
5.0
|
5.1
|
|
|
10.0
|
|
||
|
Amortization
of amounts deferred-state
|
|
|
(3.3
|
)
|
(1.9
|
)
|
|
(2.1
|
)
|
|
|
Amortization
of amounts deferred-federal
|
|
|
(3.0
|
)
|
(3.1
|
)
|
|
(4.0
|
)
|
|
|
Total
investment tax credits
|
|
|
(1.3
|
)
|
0.1
|
|
|
3.9
|
||
|
Synthetic
fuel tax credits - federal
|
|
|
-
|
(134.2
|
)
|
|
40.5
|
|
||
|
Total
income tax expense (benefit)
|
|
$
|
119.4
|
$
|
(118.0
|
)
|
$
|
122.7
|
|
|
The
difference between actual income tax expense (benefit) and that amount
calculated from the application of the statutory 35% federal income tax rate
to
pre-tax income (before cumulative effect of accounting change) is reconciled
as
follows:
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
|
|
Millions
of dollars
|
|
|||||||
|
Income
|
$
|
304.0
|
$
|
319.5
|
$
|
257.1
|
||||
|
Income
tax expense (benefit)
|
|
|
119.4
|
|
(118.0
|
)
|
|
122.7
|
|
|
|
Preferred
stock dividends
|
|
|
7.3
|
|
7.3
|
|
|
7.3
|
|
|
|
Total
pre-tax income
|
|
$
|
430.7
|
$
|
208.8
|
|
$
|
387.1
|
|
|
|
Income
taxes on above at statutory federal income tax rate
|
|
$
|
150.7
|
$
|
73.1
|
|
$
|
135.5
|
|
|
|
Increases
(decreases) attributed to:
|
|
|
|
|
|
|
|
|
||
|
State
income taxes (less federal income tax effect)
|
|
|
10.9
|
|
4.8
|
|
|
5.3
|
|
|
|
Synthetic
fuel tax credits
|
|
|
(33.5
|
)
|
|
(181.9
|
)
|
|
(2.9
|
)
|
|
Allowance
for equity funds used during construction
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
|
(5.5
|
)
|
|
Deductible
dividends-Stock Purchase Savings Plan
|
|
|
(6.5
|
)
|
|
(5.9
|
)
|
|
(5.5
|
)
|
|
Amortization
of federal investment tax credits
|
|
|
(3.0
|
)
|
|
(3.1
|
)
|
|
(4.0
|
)
|
|
Non-taxable
recovery of Lake Murray back-up dam project carrying costs
|
|
|
(2.3
|
)
|
|
(3.8
|
)
|
|
-
|
|
|
Other
differences, net
|
|
|
3.3
|
|
(1.0
|
)
|
|
(0.2
|
)
|
|
|
Total
income tax expense (benefit)
|
|
$
|
119.4
|
$
|
(118.0
|
)
|
$
|
122.7
|
|
|
The
tax
effects of significant temporary differences comprising the Company's net
deferred tax liability of $913.0 million at December 31, 2006 and
$914.5 million at December 31, 2005 are as follows:
|
|
|
2006
|
2005
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Deferred
tax assets:
|
|
|
|
|
|
||
|
Nondeductible
reserves
|
|
$
|
103.8
|
$
|
84.8
|
|
|
|
Unamortized
investment tax credits
|
|
|
58.9
|
|
60.0
|
|
|
|
Federal
alternative minimum tax credit carryforward
|
|
|
22.1
|
|
44.0
|
|
|
|
Deferred
compensation
|
|
|
29.0
|
|
28.5
|
|
|
|
Unbilled
revenue
|
|
|
12.5
|
|
12.6
|
|
|
|
Other
|
|
|
38.6
|
|
31.6
|
|
|
|
Total
deferred tax assets
|
|
|
264.9
|
|
261.5
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
||
|
Property,
plant and equipment
|
|
|
966.8
|
|
971.7
|
|
|
|
Pension
plan income
|
|
|
71.1
|
|
109.9
|
|
|
|
Deferred
employee benefit plan costs
|
56.1
|
-
|
|||||
|
Deferred
fuel costs
|
|
|
25.9
|
|
45.1
|
|
|
|
Other
|
|
|
58.0
|
|
49.3
|
|
|
|
Total
deferred tax liabilities
|
|
|
1,177.9
|
|
1,176.0
|
|
|
|
Net
deferred tax liability
|
|
$
|
913.0
|
$
|
914.5
|
|
|
The
Internal Revenue Service has completed examinations of the Company's
consolidated federal income tax returns through 2004, and the Company’s tax
returns through 2001 are closed for additional assessment. The IRS is currently
examining S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which the
Company has an interest, for the 2004 tax year. The Company does not anticipate
that any adjustments which might result from the examination will have a
material impact on the earnings or the financial position of the Company. The
Company continues to believe that all of its synthetic fuel tax credits have
been properly claimed.
9. FINANCIAL
INSTRUMENTS
Financial
instruments for which the carrying amount does not equal estimated fair value
at
December 31, 2006 and 2005 were as follows:
|
|
|
2006
|
2005
|
|
||||||||||
|
|
|
Carrying
Amount
|
Estimated
Fair
Value
|
Carrying
Amount
|
Estimated
Fair
Value
|
|
||||||||
|
|
|
Millions
of dollars
|
|
|||||||||||
|
Long-term
debt
|
|
$
|
3,110.0
|
$
|
3,207.9
|
|
$
|
3,136.0
|
|
$
|
3,308.7
|
|
||
|
Preferred
stock (subject to purchase or sinking funds)
|
|
|
8.3
|
7.8
|
|
|
8.8
|
|
|
8.2
|
|
|||
The
following methods and assumptions were used to estimate the fair value of
financial instruments:
Fair
values of long-term debt are based on quoted market prices of the instruments
or
similar instruments. For debt instruments for which no quoted market prices
are
available, fair values are based on net present value calculations. Carrying
values reflect the fair values of interest rate swaps based on settlement values
obtained from counterparties. Early settlement of long-term debt may not be
possible or may not be considered prudent.
The
fair
value of preferred stock (subject to purchase or sinking funds) is estimated
using market prices.
Potential
taxes and other expenses that would be incurred in an actual sale or settlement
have not been considered.
Investments
SCANA
and
certain of its subsidiaries hold investments, some of which are marketable
securities which are subject to SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities,"
mark-to-market accounting and some of which are considered cost basis
investments for which determination of fair value historically has been
considered impracticable or which are otherwise non-marketable, such as life
insurance policies. Equity holdings subject to SFAS 115 are categorized as
"available for sale" and are carried at quoted market prices, with any
unrealized gains and losses credited or charged to other comprehensive income
(loss) within common equity on the Company's balance sheet. When indicated,
and
in accordance with its stated accounting policy, the Company performs periodic
assessments of whether any decline in the value of these securities to amounts
below the Company's cost basis is other than temporary. When other than
temporary declines occur, write-downs are recorded through operations, and
new
(lower) cost bases are established. Insurance policies are carried at net cash
surrender value. The Company also holds investments in several partnerships
and
joint ventures which are accounted for using the equity method.
Derivatives
SFAS 133,
“Accounting
for Derivative Instruments and Hedging Activities”
as
amended, requires the Company to recognize all derivative instruments as either
assets or liabilities in the statement of financial position and to measure
those instruments at fair value. SFAS 133 further provides that changes in
the fair value of derivative instruments are either recognized in earnings
or
reported as a component of other comprehensive income (loss), depending upon
the
intended use of the derivative and the resulting designation. The fair value
of
derivative instruments is determined by reference to quoted market prices of
listed contracts, published quotations or quotations from independent
parties.
Policies
and procedures and risk limits are established to control the level of market,
credit, liquidity and operational and administrative risks assumed by the
Company. SCANA's Board of Directors has delegated to a Risk Management Committee
the authority to set risk limits, establish policies and procedures for risk
management and measurement, and oversee and review the risk management process
and infrastructure. The Risk Management Committee, which is comprised of certain
officers, including the Company's Risk Management Officer and senior officers,
apprises the Board of Directors with regard to the management of risk and brings
to the Board's attention any areas of concern. Written policies define the
physical and financial transactions that are approved, as well as the
authorization requirements and limits for transactions.
Commodities
The
Company uses derivative instruments to hedge forward purchases of natural gas,
which create market risks of different types. Instruments designated as cash
flow hedges are used to hedge risks associated with fixed price obligations
in a
volatile market and risks associated with price differentials at different
delivery locations. The basic types of financial instruments utilized are
exchange-traded instruments, such as New York Mercantile Exchange (NYMEX)
futures contracts or options, and over-the-counter instruments such as options
and swaps, which are typically offered by energy and financial
institutions.
The
Company’s regulated gas operations (SCE&G and PSNC Energy) hedge gas
purchasing activities using over-the-counter options and swaps and NYMEX futures
and options. SCE&G’s tariffs include a purchased gas adjustment (PGA) clause
that provides for the recovery of actual gas costs incurred. The SCPSC has
ruled
that the results of these hedging activities are to be included in the PGA.
As
such, costs of related derivatives utilized to hedge gas purchasing activities
are recoverable through the weighted average cost of gas calculation. The offset
to the change in fair value of these derivatives is recorded as a regulatory
asset or liability. PSNC Energy's tariffs include a provision for the recovery
of actual gas costs incurred. PSNC Energy records premiums, transaction fees,
margin requirements and any realized and unrealized gains or losses from its
hedging program in deferred accounts as a regulatory asset or liability for
the
over- or under-recovery of gas costs.
The
Company’s nonregulated gas operations recognize gains and losses as a result of
qualifying cash flow hedges whose hedged transactions occur during the reporting
period and record them, net of taxes, in cost of gas. The Company recognized
gains (losses) of approximately $(27.6) million, $4.0 million and $6.4 million
during the years ended December 31, 2006, 2005 and 2004, respectively. Because
these gains and losses resulted from hedging activities, their effects were
necessarily offset by the recording of the related hedged transactions.
The Company estimates that most of the December 31, 2006 unrealized loss balance
of $(17.6) million, net of tax, will be reclassified from accumulated other
comprehensive income (loss) to earnings in 2007 as an increase to gas cost
if
market prices remain at current levels. As of December 31, 2006, all of the
Company's cash flow hedges settle by their terms before the end of April
2009.
Interest
Rates
The
Company uses interest rate swap agreements to manage interest rate risk. These
swaps provide for the Company to pay variable and receive fixed rate interest
payments and are designated as fair value hedges of certain debt instruments.
The Company may terminate a swap and may replace it with a new swap also
designated as a fair value hedge. At December 31, 2006 the estimated fair
value of the Company's swaps totaled $0.1 million related to combined
notional amounts of $44.2 million.
Payments
received upon termination of a swap are recorded as basis adjustments to
long-term debt and are amortized as reductions to interest expense over the
term
of the underlying debt. The fair value of the swaps is recorded within other
deferred debits or credits on the balance sheet. The resulting entries serve
to
reflect the hedged long-term debt at its fair value. Periodic receipts or
payments related to the swaps are credited or charged to interest expense as
incurred.
In
anticipation of the issuance of debt, the Company may use interest rate lock
or
similar agreements to manage interest rate risk. These arrangements are
designated as cash flow hedges. As such, payments received or made upon
termination of such agreements are amortized to interest expense over the term
of the underlying debt. As
permitted by SFAS 104 “Statement
of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and
Classification of Cash Flows from Hedging Transactions,” payments
received or made are classified as a financing activity in the consolidated
statement of cash flows.
10. COMMITMENTS
AND CONTINGENCIES
A.
Nuclear Insurance
The
Price-Anderson Indemnification Act deals with public liability for a nuclear
incident and establishes the liability limit for third-party claims associated
with any nuclear incident at $10.5 billion. Each reactor licensee is
currently liable for up to $100.6 million per reactor owned for each
nuclear incident occurring at any reactor in the United States, provided that
not more than $15 million of the liability per reactor would be assessed
per year. SCE&G's maximum assessment, based on its two-thirds ownership of
Summer Station, would be approximately $67.1 million per incident, but not
more than $15 million per year.
SCE&G
currently maintains policies (for itself and on behalf of Santee Cooper, the
one-third owner of Summer Station) with Nuclear Electric Insurance Limited.
The
policies, covering the nuclear facility for property damage, excess property
damage and outage costs, permit retrospective assessments under certain
conditions to cover insurer's losses. Based on the current annual premium,
SCE&G's portion of the retrospective premium assessment would not exceed
$14.1 million.
To
the
extent that insurable claims for property damage, decontamination, repair and
replacement and other costs and expenses arising from a nuclear incident at
Summer Station exceed the policy limits of insurance, or to the extent such
insurance becomes unavailable in the future, and to the extent that SCE&G's
rates would not recover the cost of any purchased replacement power, SCE&G
will retain the risk of loss as a self-insurer. SCE&G has no reason to
anticipate a serious nuclear incident at Summer Station. However, if such an
incident were to occur, it would have a material adverse impact on the Company's
results of operations, cash flows and financial position.
B.
Environmental
South
Carolina Electric & Gas Company
In
March
2005 the United States Environmental Protection Agency (EPA) issued a final
rule
known as the Clean Air Interstate Rule (CAIR). CAIR requires the District of
Columbia and 28 states, including South Carolina, to reduce nitrogen oxide
and
sulfur dioxide emissions in order to attain mandated state levels. SCE&G has
petitioned the United States Court of Appeals for the District of Columbia
Circuit to review CAIR. Several other electric utilities have filed separate
petitions. The petitioners seek a change in the method CAIR uses to allocate
sulfur dioxide emission allowances to a method the petitioners believe is more
equitable. The Company believes that installation of additional air quality
controls will be needed to meet the CAIR requirements. Compliance plans and
cost
to comply with the rule will be determined once the Company completes its
review. Such costs will be material and are expected to be recoverable through
rates.
In
March
2005, the EPA issued a final rule establishing a mercury emissions cap and
trade
program for coal-fired power plants that requires limits to be met in two
phases, in 2010 and 2018. Although the Company expects to be able to meet the
Phase I limits through those measures it already will be taking to meet its
CAIR
obligations, it is uncertain as to how the Phase II limits will be met. Assuming
Phase II limits remain unchanged, installation of additional air quality
controls likely will be required to comply with the rule’s Phase II mercury
emission caps. Final compliance plans and costs to comply with the rule are
still under review. Such costs will be material and are expected to be
recoverable through rates.
SCE&G
has been named, along with 53 others, by the EPA as a PRP at the Alternate
Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.
The EPA placed the site on the National Priorities List on April 19, 2006.
AER
conducted hazardous waste storage and treatment operations from 1975 to 2000,
when the site was abandoned. While operational, AER processed fuels from
waste oils, treated industrial coolants and oil/water emulsions, recycled
solvents and blended hazardous waste fuels. During that time, SCE&G
occasionally used AER for the processing of waste solvents, oily rags and oily
wastewater. EPA and the State of Georgia have documented that a release or
releases have occurred at the site leading to contamination of groundwater,
surface water and soils. EPA and the State of Georgia have conducted a
preliminary assessment and site inspection. The site has not been cleaned up
nor
has a cleanup cost been estimated. Although a basis for the allocation of
clean-up costs among the PRPs is unclear, SCE&G does not believe that its
involvement at this site would result in an allocation of costs that would
have
a material adverse impact on its results of operations, cash flows or financial
condition. Any cost allocated to SCE&G arising from the remediation of this
site, net of insurance recoveries, if any, is expected to be recoverable through
rates.
SCE&G
has been named, along with 29 others, by the EPA as a potentially responsible
party (PRP) at the Carolina Transformer Superfund site located in Fayetteville,
North Carolina. The Carolina Transformer Company (CTC) conducted an
electrical transformer rebuilding and repair operation at the site from 1967
to
1984. During that time, SCE&G occasionally used CTC for the repair of
existing transformers, purchase of new transformers and sale of used
transformers. In 1984, EPA initiated a cleanup of PCB-contaminated soil
and groundwater at the site. EPA reports that it has spent $36 million to
date. Although a basis for the allocation of clean-up costs among the PRPs
is unclear, SCE&G does not believe that its involvement at this site would
result in an allocation of costs that would have a material adverse impact
on
its results of operations, cash flows or financial condition. Any cost allocated
to SCE&G arising from the remediation of this site, net of insurance
recoveries, if any, is expected to be recoverable through rates.
SCE&G
defers site assessment and cleanup costs and recovers them through rates (see
Note 1). Deferred amounts, net of amounts previously recovered through rates
and
insurance settlements, totaled $17.9 million at December 31, 2006. The deferral
includes the estimated costs associated with the following matters.
SCE&G
owns a decommissioned MGP site in the Calhoun Park area of Charleston, South
Carolina. SCE&G anticipates that remediation for contamination at the site
will be completed in late 2007, with certain monitoring and retreatment
activities continuing until 2011. As of December 31, 2006, SCE&G had spent
$22.3 million to remediate the site and expects to spend an additional $1.1
million prior to entering a monitoring and reporting stage. In addition, the
National Park Service of the Department of the Interior made an initial demand
to SCE&G for payment of $9.1 million for certain costs and damages relating
to this site. SCE&G
expects to recover any cost arising from the remediation of this site through
rates.
SCE&G
owns three other decommissioned MGP sites in South Carolina which contain
residues of by-product chemicals. One of the sites has been remediated and
will
undergo routine monitoring until released by DHEC. The other sites are currently
being investigated under work plans approved by DHEC. SCE&G anticipates that
major remediation activities for the three sites will be completed by 2011.
As
of December 31, 2006, SCE&G has spent $4.8 million related to these
three sites, and expects to spend an additional $11.2 million. SCE&G expects
to recover any cost arising from the remediation of these sites through
rates.
Public
Service Company of North Carolina, Incorporated
PSNC
Energy is responsible for environmental cleanup at five sites in North Carolina
on which MGP residuals are present or suspected. PSNC Energy's actual
remediation costs for these sites will depend on a number of factors, such
as
actual site conditions, third-party claims and recoveries from other PRPs.
PSNC
Energy has recorded a liability and associated regulatory asset of
$6.9 million, which reflects its estimated remaining liability at
December 31, 2006. PSNC Energy expects to recover any cost allocable to
PSNC Energy arising from the remediation of these sites through
rates.
C.
Franchise
Agreements
See
Note 1B for a discussion of the electric and gas franchise agreements
between SCE&G and the cities of Columbia and Charleston.
D.
Claims
and Litigation
In
1999,
an unsuccessful bidder for the purchase of certain propane gas assets of the
Company filed suit against SCANA in Circuit Court, seeking unspecified damages.
The suit alleged the existence of a contract for the sale of assets to the
plaintiff and various causes of action associated with that contract. On
October 21, 2004, the jury issued an adverse verdict on this matter against
SCANA for four causes of action for damages totaling $48 million. In
accordance with generally accepted accounting principles, in the third quarter
of 2004 SCANA accrued a liability of $18 million, which was its reasonable
estimate of the minimum liability that was probable if the final judgment were
to be consistent with the jury verdict. While the judgment was being appealed,
in May 2006 SCANA paid the plaintiff $11 million in settlement of its claims.
A claim
against SCANA for $2.7 million for reimbursement of legal fees and expenses
under an indemnification and hold harmless agreement in the contract for the
sale of the propane gas assets was settled in November 2006. A
provision for this loss had been previously recorded.
In
August
2003, SCE&G was served as a co-defendant in a purported class action lawsuit
styled as Collins v. Duke Energy Corporation, Progress Energy Services Company,
and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth
Judicial Circuit. Since that time, the plaintiffs have dismissed defendants
Duke
Energy and Progress Energy and are proceeding against SCE&G only. The
plaintiffs are seeking damages for the alleged improper use of electric
transmission and distribution easements but have not asserted a dollar amount
for their claims. Specifically, the plaintiffs contend that the licensing of
attachments on electric utility poles, towers and other facilities to nonutility
third parties or telecommunication companies for other than the electric
utility’s internal use along the electric transmission and distribution line
rights-of-way constitutes a trespass. It is anticipated that this case may
not
go to trial before 2008. SCANA and SCE&G are confident of the propriety of
SCE&G’s actions and intend to mount a vigorous defense. SCANA and SCE&G
further believe that the resolution of these claims will not have a material
adverse impact on their results of operations, cash flows or financial
condition.
In
May 2004, SCANA and SCE&G were served with a purported class action
lawsuit styled as Douglas E. Gressette, individually and on behalf of other
persons similarly situated v. South Carolina Electric & Gas Company and
SCANA Corporation. The case was filed in South Carolina's Circuit Court of
Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA
and SCE&G made improper use of certain easements and rights-of-way by
allowing fiber optic communication lines and/or wireless communication equipment
to transmit communications other than SCANA’s and SCE&G’s
electricity-related internal communications. The plaintiff asserted causes
of
action for unjust enrichment, trespass, injunction and declaratory judgment.
The
plaintiff did not assert a specific dollar amount for the claims. SCANA &
SCE&G believe their actions are consistent with governing law and the
applicable documents granting easements and rights-of-way. The Circuit Court
granted SCANA’s and SCE&G’s motion to dismiss and issued an order dismissing
the case in June 2005. The
plaintiff appealed to the South Carolina Supreme Court. The Supreme Court
overruled the Circuit Court in October 2006 and returned the case to the Circuit
Court for further consideration. It is anticipated that this case may not go
to
trial before 2008. SCANA and SCE&G will continue to mount a vigorous
defense and believes that the resolution of these claims will not have a
material adverse impact on its results of operations, cash flows or financial
condition.
A
complaint was filed in October 2003 against SCE&G by the State of South
Carolina alleging that SCE&G violated the Unfair Trade Practices Act by
charging municipal franchise fees to some customers residing outside a
municipality's limits. The complaint alleged that SCE&G failed to obey,
observe or comply with the lawful order of the SCPSC by charging franchise
fees
to those not residing within a municipality. The complaint sought restitution
to
all affected customers and penalties of up to $5,000 for each separate
violation. The claim against SCE&G has been settled by an agreement between
the parties, and the settlement has been approved by South
Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. In
addition, SCE&G filed a petition with the SCPSC in October 2003 pursuant to
S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its
jurisdiction to investigate the operation of the municipal franchise fee
collection requirements applicable to SCE&G’s electric and gas service, to
approve SCE&G’s efforts to correct any past franchise fee billing errors, to
adopt improvements in the system which will reduce such errors in the future,
and to adopt any regulation that the SCPSC deems just and proper to regulate
the
franchise fee collection process. A hearing on this petition has not been
scheduled. The Company believes that the resolution of these matters will not
have a material adverse impact on its results of operations, cash flows or
financial condition.
The
Company is also engaged in various other claims and litigation incidental to
its
business operations which management anticipates will be resolved without a
material adverse impact on the Company’s results of operations, cash flows or
financial condition.
E. Settlement
Related to Power Marketing Practices
On
January 18, 2007 FERC approved a settlement with SCE&G regarding the use of
SCE&G’s electric transmission system by its power marketing division.
SCE&G identified, investigated and self-reported instances of improper
utilization of network transmission services, rather than point-to-point
transmission services, for purchases and sales of electricity in violation
of
SCE&G’s open access transmission tariff and applicable FERC orders under the
Federal Power Act that prohibit the use of network transmission service in
support of certain “off-system” sales.
As
part
of the settlement, SCE&G agreed that it would not retain any benefit derived
from the transactions. SCE&G paid a $9 million penalty to the U.S. Treasury.
Additionally, SCE&G agreed to credit
an
additional $1.4 million to benefit retail native load ratepayers and SCE&G’s
non-affiliated firm transmission customers. The credit to the retail native
load
ratepayers was applied toward the fuel clause mechanism in January 2007. The
credit to the non-affiliated firm transmission customers was refunded directly
to those customers. An additional $0.4 million was credited to transmission
revenue to the benefit of SCE&G’s rate payers. The effects of the settlement
were accrued in 2006.
F.
Operating
Lease Commitments
The
Company is obligated under various operating leases with respect to office
space, furniture and equipment. Leases expire at various dates through 2013.
Rent expense totaled approximately $15.0 million, $13.9 million and
$11.8 million in 2006, 2005 and 2004, respectively. Future minimum rental
payments under such leases are as follows:
|
|
|
Millions
of dollars
|
|
|
|
2007
|
|
$
|
30
|
|
|
2008
|
|
|
14
|
|
|
2009
|
|
|
10
|
|
|
2010
|
|
|
1
|
|
|
2011
|
|
|
-
|
|
|
Thereafter
|
|
|
2
|
|
|
Total
|
|
$
|
57
|
|
At
December 31, 2006 minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$5.7 million.
G.
Purchase
Commitments
The
Company is obligated for purchase commitments that expire at various dates
through 2034. Amounts expended under forward contracts for natural gas
purchases, gas transportation capacity agreements, coal supply contracts,
nuclear fuel contracts, construction projects and other commitments totaled
$2.4 billion, $2.2 billion and $1.6 billion in 2006, 2005 and 2004,
respectively. Future payments under such purchase commitments are as
follows:
|
|
|
Millions
of dollars
|
|
|
|
|
|
|
|
|
|
2007
|
|
$
|
1,623
|
|
|
2008
|
|
|
811
|
|
|
2009
|
|
|
1,221
|
|
|
2010
|
|
|
548
|
|
|
2011
|
|
|
499
|
|
|
Thereafter
|
|
|
3,459
|
|
|
Total
|
|
$
|
8,161
|
|
Forward
contracts for natural gas purchases include customary "make-whole" or default
provisions, but are not considered to be "take-or-pay" contracts.
In
addition, included in purchase commitments are customary purchase orders under
which the Company has the option to utilize certain vendors without the
obligation to do so. The Company may terminate such commitments without
penalty.
H. Asset
Retirement Obligations
In
accordance with SFAS 143, “Accounting
for Asset Retirement Obligations,”
as
interpreted by FIN 47, “Accounting
for Conditional Asset Retirement Obligations,”
the
Company recognizes a liability for the fair value of an ARO when incurred if
the
fair value of the liability can be reasonably estimated. Uncertainty about
the
timing or method of settlement of a conditional ARO is factored into the
measurement of the liability when sufficient information exists, but such
uncertainty is not a basis upon which to avoid liability recognition.
SFAS 143
applies to the legal obligation associated with the retirement of long-lived
tangible assets that result from their acquisition, construction, development
and normal operation and relates primarily to the Company’s regulated utility
operations. As of December 31, 2006, the Company has recorded an ARO of
approximately $92 million for nuclear plant decommissioning (see Note 1G) and
an
ARO of approximately $199 million for other conditional obligations related
to
generation, transmission and distribution properties, including gas pipelines.
All of the amounts recorded are based upon estimates which are subject to
varying degrees of imprecision, particularly since such payments will be made
many years in the future.
A
reconciliation of the beginning and ending aggregate carrying amount of asset
retirement obligations is as follows:
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Beginning
balance
|
|
$
|
322
|
|
$
|
124
|
|
|
Liabilities
incurred
|
1
|
-
|
|||||
|
Liabilities
settled
|
(2
|
)
|
-
|
||||
|
Accretion
expense
|
|
|
17
|
|
|
7
|
|
|
Revisions
in estimated cash flows
|
(46
|
)
|
-
|
||||
|
Adoption
of FIN 47
|
|
|
-
|
|
|
191
|
|
|
Ending
Balance
|
|
$
|
292
|
|
$
|
322
|
|
Revisions
in estimated cash flows relate to the estimated ARO associated with
decommissioning Summer Station. The reduction is primarily related to the
expectation of lower decommissioning cost escalations than had been assumed
in
the prior cash flow analysis.
11. SEGMENT
OF BUSINESS INFORMATION
The
Company's reportable segments are described below. The accounting policies
of
the segments are the same as those described in the summary of significant
accounting policies. The Company records intersegment sales and transfers of
electricity and gas based on rates established by the appropriate regulatory
authority. Nonregulated sales and transfers are recorded at current market
prices.
Electric
Operations is primarily engaged in the generation, transmission and distribution
of electricity, and is regulated by the SCPSC and FERC.
Gas
Distribution, comprised of the local distribution operations of SCE&G and
PSNC Energy, is engaged in the purchase and sale, primarily at retail, of
natural gas. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC,
respectively.
Gas
Transmission is comprised of CGTC which, effective November 1, 2006, began
operating as an open access, transportation-only pipeline company regulated
by
FERC. CGTC resulted from the merger of SCG Pipeline (previously reported in
All
Other) into SCPC. Prior to the merger, SCPC purchased, transported and sold
natural gas intrastate and SCG Pipeline transported gas interstate. The results
for CGTC, SCPC and SCG Pipeline appear in the Gas Transmission reportable
segment for all periods presented.
Retail
Gas Marketing markets natural gas in Georgia and is regulated as a marketer
by
the Georgia Public Service Commission. Energy Marketing markets electricity
and
natural gas to industrial, large commercial and wholesale customers, primarily
in the Southeast.
The
Company's regulated reportable segments share a similar regulatory environment
and, in some cases, overlapping service areas. However, Electric Operations'
product differs from the other segments, as does its generation process and
method of distribution. The gas segments differ from each other in their
regulatory environment, the class of customers each serves and the marketing
strategies resulting from those differences. The marketing segments differ
from
each other in their respective markets and customer type.
Disclosure
of Reportable Segments (Millions of dollars)
|
2006
|
Electric
Operations
|
Gas
Distribution
|
Gas
Transmission
|
Retail
Gas
Marketing
|
Energy
Marketing
|
All
Other
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|
||||||||||||||||
|
Customer
Revenue
|
|
$
|
1,877
|
$
|
1,078
|
$
|
179
|
$
|
608
|
$
|
821
|
$
|
66
|
$
|
(66
|
)
|
$
|
4,563
|
|
||||||
|
Intersegment
Revenue
|
|
|
9
|
-
|
322
|
-
|
128
|
306
|
(765
|
)
|
-
|
|
|||||||||||||
|
Operating
Income
|
|
|
456
|
83
|
30
|
n/a
|
n/a
|
n/a
|
34
|
603
|
|
||||||||||||||
|
Interest
Expense
|
|
|
15
|
24
|
7
|
2
|
-
|
-
|
161
|
209
|
|
||||||||||||||
|
Depreciation
and Amortization
|
|
|
268
|
54
|
8
|
3
|
-
|
15
|
(15
|
)
|
333
|
|
|||||||||||||
|
Income
Tax Expense (Benefit)
|
|
|
3
|
16
|
11
|
19
|
-
|
6
|
64
|
119
|
|||||||||||||||
|
Net
Income (Loss)
|
|
|
n/a
|
n/a
|
n/a
|
30
|
-
|
(11
|
)
|
291
|
310
|
|
|||||||||||||
|
Segment
Assets
|
|
|
5,520
|
1,847
|
315
|
208
|
142
|
649
|
1,136
|
9,817
|
|
||||||||||||||
|
Expenditures
for Assets
|
|
|
304
|
174
|
13
|
-
|
3
|
35
|
(2
|
)
|
527
|
|
|||||||||||||
|
Deferred
Tax Assets
|
|
|
n/a
|
n/a
|
7
|
3
|
12
|
2
|
10
|
34
|
|
||||||||||||||
|
2005
|
|
Electric
Operations
|
Gas
Distribution
|
Gas
Transmission
|
Retail
Gas
Marketing
|
Energy
Marketing
|
All
Other
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|
|||||||||||||||
|
Customer
Revenue
|
|
$
|
1,909
|
|
$
|
1,168
|
|
$
|
237
|
|
$
|
664
|
|
$
|
799
|
|
$
|
70
|
|
$
|
(70
|
)
|
$
|
4,777
|
|
|
Intersegment
Revenue
|
|
|
4
|
|
|
1
|
|
|
427
|
|
|
-
|
|
|
146
|
|
|
317
|
|
|
(895
|
)
|
|
-
|
|
|
Operating
Income
|
|
|
299
|
|
|
75
|
|
|
26
|
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
|
36
|
|
|
436
|
|
|
Interest
Expense
|
|
|
13
|
|
|
21
|
|
|
7
|
|
|
2
|
|
|
-
|
|
|
-
|
|
|
169
|
|
|
212
|
|
|
Depreciation
and Amortization
|
|
|
450
|
|
|
49
|
|
|
8
|
|
|
3
|
|
|
-
|
|
|
13
|
|
|
(13
|
)
|
|
510
|
|
|
Income
Tax Expense (Benefit)
|
|
|
4
|
|
|
18
|
|
|
8
|
|
|
14
|
|
|
(1
|
)
|
|
12
|
|
|
(173
|
)
|
|
(118
|
)
|
|
Net
Income (Loss)
|
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
|
24
|
|
|
(1
|
)
|
|
(69
|
)
|
|
366
|
|
|
320
|
|
|
Segment
Assets
|
|
|
5,531
|
|
|
1,701
|
|
|
427
|
|
|
284
|
|
|
128
|
|
|
553
|
|
|
895
|
|
|
9,519
|
|
|
Expenditures
for Assets
|
|
|
280
|
|
|
122
|
|
|
5
|
|
|
-
|
|
|
1
|
|
|
18
|
|
|
(41
|
)
|
|
385
|
|
|
Deferred
Tax Assets
|
|
|
n/a
|
|
|
n/a
|
|
|
6
|
|
|
8
|
|
|
3
|
|
|
2
|
|
|
7
|
|
|
26
|
|
|
2004
|
|
Electric
Operations
|
Gas
Distribution
|
Gas
Transmission
|
Retail
Gas
Marketing
|
Energy
Marketing
|
All
Other
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|
|||||||||||||||
|
Customer
Revenue
|
|
$
|
1,688
|
|
$
|
914
|
|
$
|
212
|
|
$
|
552
|
|
$
|
520
|
|
$
|
58
|
|
$
|
(59
|
)
|
$
|
3,885
|
|
|
Intersegment
Revenue
|
|
|
4
|
|
|
-
|
|
|
346
|
|
|
-
|
|
|
77
|
|
|
297
|
|
|
(724
|
)
|
|
-
|
|
|
Operating
Income
|
|
|
550
|
|
|
67
|
|
|
23
|
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
|
(44
|
)
|
|
596
|
|
|
Interest
Expense
|
|
|
10
|
|
|
21
|
|
|
5
|
|
|
3
|
|
|
-
|
|
|
-
|
|
|
163
|
|
|
202
|
|
|
Depreciation
and Amortization
|
|
|
208
|
|
|
47
|
|
|
8
|
|
|
2
|
|
|
-
|
|
|
11
|
|
|
(11
|
)
|
|
265
|
|
|
Income
Tax Expense (Benefit)
|
|
|
(2
|
)
|
|
15
|
|
|
6
|
|
|
18
|
|
|
(1
|
)
|
|
(9
|
)
|
|
96
|
|
|
123
|
|
|
Net
Income (Loss)
|
|
|
n/a
|
|
|
n/a
|
|
|
n/a
|
|
|
29
|
|
|
(2
|
)
|
|
(42
|
)
|
|
272
|
|
|
257
|
|
|
Segment
Assets
|
|
|
5,365
|
|
|
1,540
|
|
|
393
|
|
|
201
|
|
|
91
|
|
|
470
|
|
|
946
|
|
|
9,006
|
|
|
Expenditures
for Assets
|
|
|
389
|
|
|
86
|
|
|
11
|
|
|
-
|
|
|
3
|
|
|
18
|
|
|
(6
|
)
|
|
501
|
|
|
Deferred
Tax Assets
|
|
|
n/a
|
|
|
n/a
|
|
|
5
|
|
|
4
|
|
|
3
|
|
|
2
|
|
|
(4
|
)
|
|
10
|
|
Revenues
and assets from segments below the quantitative thresholds are attributable
to
ten other direct and indirect wholly owned subsidiaries of the Company. These
subsidiaries conduct nonregulated operations in energy-related and
telecommunications industries. None of these subsidiaries met the quantitative
thresholds for determining reportable segments during any period
reported.
Management
uses operating income to measure segment profitability for SCE&G and other
regulated operations and evaluates utility plant, net, for segments attributable
to SCE&G. As a result, SCE&G does not allocate interest charges, income
tax expense (benefit) or assets other than utility plant to its segments. For
nonregulated operations, management uses net income (loss) as the measure of
segment profitability and evaluates total assets for financial position.
Interest income is not reported by segment and is not material. In accordance
with SFAS 109, the Company’s deferred tax assets are netted with deferred
tax liabilities for reporting purposes.
The
Consolidated Financial Statements report operating revenues which are comprised
of the energy-related reportable segments. Revenues from non-reportable segments
are included in Other Income. Therefore the adjustments to total operating
revenues remove revenues from non-reportable segments. Adjustments to Net Income
consist of SCE&G’s unallocated net income.
Segment
Assets include utility plant, net for SCE&G’s Electric Operations and Gas
Distribution, and all assets for PSNC Energy and the remaining segments. As
a
result, adjustments to assets include non-utility plant and non-fixed assets
for
SCE&G.
Adjustments
to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets
and
Deferred Tax Assets include primarily the totals from SCANA or SCE&G that
are not allocated to the segments. Interest Expense is also adjusted to
eliminate charges between affiliates. Adjustments to Depreciation and
Amortization consist of non-reportable segment expenses, which are not included
in the depreciation and amortization reported on a consolidated basis.
Expenditures for Assets are adjusted for AFC. Deferred Tax Assets are adjusted
to net them against deferred tax liabilities on a consolidated
basis.
12. QUARTERLY
FINANCIAL DATA (UNAUDITED)
|
2006
Millions of dollars, except per share amounts
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Annual
|
|
|||||||||
|
Total
operating revenues
|
|
$
|
1,389
|
$
|
944
|
$
|
1,062
|
$
|
1,168
|
$
|
4,563
|
|
||||
|
Operating
income
|
|
|
185
|
122
|
156
|
140
|
603
|
|
||||||||
|
Income
before cumulative effect of accounting change
|
92
|
58
|
89
|
65
|
304
|
|||||||||||
|
Cumulative
effect of accounting change, net of taxes (1)
|
6
|
-
|
-
|
-
|
6
|
|||||||||||
|
Net
income
|
|
|
98
|
58
|
89
|
65
|
310
|
|
||||||||
|
Basic
and diluted earnings per share
|
|
|
.85
|
.50
|
.76
|
.57
|
2.68
|
|
||||||||
|
2005
Millions of dollars, except per share amounts
|
|
|
||||||||||||||
|
Total
operating revenues
|
|
$
|
1,266
|
|
$
|
891
|
|
$
|
1,127
|
|
$
|
1,493
|
|
$
|
4,777
|
|
|
Operating
income
|
|
|
28
|
|
|
85
|
|
|
179
|
|
|
144
|
|
|
436
|
|
|
Net
income
|
|
|
101
|
|
|
44
|
|
|
100
|
|
|
75
|
|
|
320
|
|
|
Basic
and diluted earnings per share
|
|
|
.89
|
|
|
.39
|
|
|
.88
|
|
|
.65
|
|
|
2.81
|
|
(1)
The
cumulative effect of accounting change is attributable to the adoption of SFAS
123(R) in the first quarter of 2006.
See Note 3.
|
|
|
Page
|
|
|
|
|
|
|
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
82
|
|
|
|
|
Overview
|
82
|
|
|
|
Results
of Operations
|
83
|
|
|
|
Liquidity
and Capital Resources
|
88
|
|
|
|
Environmental
Matters
|
91
|
|
|
|
Regulatory
Matters
|
93
|
|
|
|
Critical
Accounting Policies and Estimates
|
93
|
|
|
|
Other
Matters
|
95
|
|
|
|
|
|
|
Item
7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
96
|
|
|
|
|
|
|
|
Item
8.
|
Financial
Statements and Supplementary Data
|
98
|
|
|
|
|
Report
of Independent Registered Public Accounting Firm
|
98
|
|
|
|
Consolidated
Balance Sheets
|
99
|
|
|
|
Consolidated
Statements of Income
|
101
|
|
|
|
Consolidated
Statements of Cash Flows
|
102
|
|
|
|
Consolidated
Statements of Changes in Common Equity
|
103
|
|
|
|
Notes
to Consolidated Financial Statements
|
104
|
|
|
|
|
|
ITEM
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS
OF
OPERATIONS
OVERVIEW
South
Carolina Electric & Gas Company (SCE&G, together with its consolidated
affiliates, the Company) is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity and in the
purchase and sale, primarily at retail, of natural gas. SCE&G’s business is
subject to seasonal fluctuations. Generally, sales of electricity are higher
during the summer and winter months because of air-conditioning and heating
requirements, and sales of natural gas are greater in the winter months due
to
heating requirements. SCE&G’s electric service territory extends into 24
counties covering nearly 17,000 square miles in the central, southern and
southwestern portions of South Carolina. The service area for natural gas
encompasses all or part of 35 counties in South Carolina and covers more than
23,000 square miles.
Key
earnings drivers for SCE&G over the next five years will be additions to
utility rate base, consisting primarily of capital expenditures for
environmental facilities, new generating capacity and system expansion. Other
factors that will impact future earnings growth include the regulatory
environment, customer growth and controlling the growth of operation and
maintenance expenses.
Electric
Operations
The
electric operations segment is comprised of the electric operations of
SCE&G, South Carolina Generating Company, Inc. (GENCO) and South Carolina
Fuel Company, Inc. (Fuel Company), and is primarily engaged in the generation,
transmission and distribution of electricity in South Carolina. At
December 31, 2006 SCE&G provided electricity to 623,400 customers.
GENCO owns and operates a coal-fired generation station and sells electricity
solely to SCE&G. Fuel Company acquires, owns and provides financing for
SCE&G’s nuclear fuel, fossil fuel and emission allowance requirements. Both
GENCO and Fuel Company are consolidated with SCE&G for financial reporting
purposes.
Operating
results for electric operations are primarily driven by customer demand for
electricity, the ability to control costs and rates allowed to be charged to
customers. Embedded in the rates charged to customers is an allowed regulatory
return on equity. In January 2005, as a result of an electric rate case,
SCE&G’s allowed return on equity was lowered from 12.45% to an amount not to
exceed 11.4%, with rates set at 10.7%. Demand for electricity is primarily
affected by weather, customer growth and the economy. SCE&G is able to
recover the cost of fuel used in electric generation through retail customers’
bills, but increases in fuel costs affect electric prices and, therefore, the
competitive position of electricity against other energy sources.
Legislative
and regulatory initiatives, including the Energy Policy Act of 2005 (the “Energy
Policy Act”) also could significantly impact the results of operations and cash
flows for the electric operations segment. The Energy Policy Act became law
in
August 2005, and it provides, among other things, for the establishment of
an
electric reliability organization (ERO) to propose and enforce mandatory
reliability standards for transmission systems, for procedures governing
enforcement actions by the ERO and the Federal Energy Regulatory Commission
(FERC) and for procedures under which the ERO may delegate authority to a
regional entity to enforce reliability standards.
In
February 2006 FERC issued final rules to implement the electric reliability
provisions of the Energy Policy Act. The Company is reviewing these rules and
monitoring their implementation to determine the impact they may have on
SCE&G’s access to or cost of power for its native load customers and for its
marketing of power outside its service territory. The Company cannot predict
when or if FERC will advance other regulatory initiatives related to the
national energy market or what conditions such initiatives would impose on
utilities.
New
legislation may also impose stringent requirements on power plants to reduce
emissions of sulfur dioxide, nitrogen oxides and mercury. It is also possible
that new initiatives will be introduced to reduce carbon dioxide emissions.
The
Company cannot predict whether such legislation will be enacted, and if it
is,
the conditions it would impose on utilities.
Gas
Distribution
The
gas
distribution segment is comprised of the local distribution operations of
SCE&G and is primarily engaged in the purchase and sale of natural gas to
retail customers in portions of South Carolina. At December 31, 2006 this
segment provided natural gas to approximately 297,000 customers.
Operating
results for gas distribution are primarily influenced by customer demand for
natural gas, the ability to control costs and allowed rates to be charged to
customers. Embedded in the rates charged to customers is an allowed regulatory
return on equity. This allowed return on equity is 10.25%.
Demand
for natural gas is primarily affected by weather, customer growth, the economy
and, for commercial and industrial customers, the availability and price of
alternate fuels. Natural gas competes with electricity, propane and heating
oil
to serve the heating and, to a lesser extent, other household energy needs
of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane
or
fuel oil. Natural gas competes with these alternate fuels based on price. As
a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect price and impact SCE&G’s ability to retain
large commercial and industrial customers. Significant supply disruptions did
occur in September and October 2005 as a result of hurricane activity in the
Gulf of Mexico, resulting in the curtailment during the period of most large
commercial and industrial customers with interruptible supply agreements. While
supply disruptions were not experienced in 2006 or in January or February 2007,
the price of natural gas remains volatile and has resulted in short-term
competitive pressure. The long-term impact of volatile gas prices and gas supply
has not been determined.
RESULTS
OF OPERATIONS
Net
Income
Net
income was as follows:
|
Millions
of dollars
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Net
income
|
|
$
|
234.6
|
|
|
(9.1
|
)%
|
$
|
258.1
|
|
11.0
|
%
|
$
|
232.5
|
|
|
|
•
|
2006 vs 2005
|
Net
income decreased primarily due to lower electric margin of $7.8 million,
increased electric generation, transmission and distribution expenses
of
$6.9 million, increased gas distribution expenses of $1.9 million,
a
settlement related to power marketing practices of $8.7 million (see
Note
10E of the consolidated financial statements), lower pension income
and
other postretirement benefits of $2.8 million, increased customer
service
expenses of $1.2 million and increased property taxes of $3.7 million.
These increases were partially offset by higher gas margins of $10.5
million and lower incentive compensation expense of $8.6
million.
|
|
•
|
2005 vs 2004
|
Net
income increased primarily due to higher electric and gas margins
of $50.8
million and $5.1 million, respectively, and due to the recognition
of
carrying cost recovery of $10.9 million on the dam remediation project
(see Income Taxes
- Recognition of Synthetic Fuel Tax Credits).
These increases were offset by higher major maintenance expenses
of $4.1
million, higher depreciation and amortization expense of $16.1 million,
increased interest expense of $3.3 million, increased expenses of
$5.5
million associated with the Jasper County Electric Generation Station
completed in May 2004, lower equity AFC of $14.3 million and higher
other
expenses of $2.3 million.
|
Pension
Income
Pension
income was recorded on SCE&G’s financial statements as follows:
|
Millions
of dollars
|
2006
|
2005
|
2004
|
|
||||||
|
|
|
|
|
|||||||
|
Income
Statement Impact:
|
|
|
|
|
|
|
|
|||
|
Reduction
in employee benefit costs
|
|
$
|
2.4
|
$
|
5.6
|
|
$
|
4.2
|
||
|
Other
income
|
|
|
12.7
|
12.2
|
|
|
11.0
|
|
||
|
Balance
Sheet Impact:
|
|
|
|
|
|
|
|
|||
|
Reduction
in capital expenditures
|
|
|
0.7
|
1.6
|
|
|
1.2
|
|||
|
Component
of amount due to Summer Station co-owner
|
|
|
0.2
|
0.6
|
|
|
0.4
|
|||
|
Total
Pension Income
|
|
$
|
16.0
|
$
|
20.0
|
|
$
|
16.8
|
|
|
For
the
last several years, the market value of SCE&G’s retirement plan (pension)
assets has exceeded the total actuarial present value of accumulated plan
benefits. Among the reasons 2006’s income was lower than 2005’s was a reduction
of the assumed rate of return on assets from 9.25% to 9%. See also the
discussion of pension accounting in Critical Accounting Policies and
Estimates.
Allowance
for Funds Used During Construction (AFC)
AFC
is a
utility accounting practice whereby a portion of the cost of both equity and
borrowed funds used to finance construction (which is shown on the balance
sheet
as construction work in progress) is capitalized. The Company includes an equity
portion of AFC in nonoperating income and a debt portion of AFC in interest
charges (credits) as noncash items, both of which have the effect of increasing
reported net income. AFC represented approximately 2.2% of income before income
taxes in 2006, 1.5% in 2005 and 6.5% in 2004. The lower level of AFC for 2005
is
primarily due to reductions in the levels of capital expenditures subsequent
to
the completion of the Jasper County Electric Generation Station in May 2004
and
completion of the Lake Murray back-up dam project in May 2005.
Dividends
Declared
SCE&G’s
Board of Directors has declared the following dividends on common stock held
by
SCANA during 2006:
|
Declaration
Date
|
Dividend
Amount
|
Quarter Ended
|
Payment Date
|
|
February
16, 2006
|
$39.2
million
|
March
31, 2006
|
April
1, 2006
|
|
April
27, 2006
|
$39.2
million
|
June
30, 2006
|
July
1, 2006
|
|
August
3, 2006
|
$39.2
million
|
September 30, 2006
|
October
1, 2006
|
|
November
1, 2006
|
$21.0
million
|
December
31, 2006
|
January
1, 2007
|
Electric
Operations
Electric
Operations is comprised of the electric operations of SCE&G, GENCO and Fuel
Company. Electric operations sales margins were as follows:
|
Millions
of dollars
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
||||||||||||
|
|
|
|
|
|||||||||||||||
|
Operating
revenues
|
|
$
|
1,886.6
|
|
|
(1.3
|
)%
|
$
|
1,912.0
|
|
|
13.0
|
%
|
$
|
1,692.0
|
|
||
|
Less:
Fuel used in generation
|
|
|
615.1
|
|
|
(0.5
|
)%
|
|
618.1
|
|
|
32.4
|
%
|
|
466.9
|
|
||
|
Purchased
power
|
|
|
27.5
|
|
|
(26.1
|
)%
|
|
37.2
|
|
|
(26.6
|
)%
|
|
50.7
|
|
||
|
Margin
|
|
$
|
1,244.0
|
|
|
(1.0
|
)%
|
$
|
1,256.7
|
|
|
7.0
|
%
|
$
|
1,174.4
|
|
||
|
•
|
2006 vs 2005
|
Margin
decreased by $20.8 million due to unfavorable weather, by $16.0 million
due to decreased off-system sales and by $6.5 million due to lower
industrial sales. These decreases were offset by residential and
commercial customer growth of $26.5 million and increased other electric
revenue of $4.1 million. Purchased power cost decreased due to lower
volumes.
|
|
•
|
2005 vs 2004
|
Margin
increased by $41.4 million due to increased retail electric rates
that
went into effect in January 2005, by $24.8 million due to residential
and
commercial customer growth and by $16.4 million due to increased
off-system sales. These increases were offset by a $2.4 million decrease
due to unfavorable weather. Fuel used in generation increased $151.2
million due primarily to the increased cost of coal and natural gas
used
for electric generation. Purchased power cost decreased due to greater
availability of generation
facilities.
|
Megawatt
hour (MWh) sales volumes by class, related to the electric margin above, were
as
follows:
|
Classification
(in thousands)
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
|||||||||
|
Residential
|
|
|
7,598
|
|
|
(0.5
|
)%
|
|
7,634
|
|
2.3
|
%
|
|
7,460
|
|
|
|
Commercial
|
|
|
7,268
|
|
|
1.9
|
%
|
|
7,135
|
|
3.1
|
%
|
|
6,919
|
|
|
|
Industrial
|
|
|
6,183
|
|
|
(6.0
|
)%
|
|
6,581
|
|
(2.9
|
)%
|
|
6,775
|
|
|
|
Sales
for resale (excluding interchange)
|
|
|
1,487
|
|
|
-
|
|
1,487
|
|
(2.5
|
)%
|
|
1,525
|
|
||
|
Other
|
|
|
531
|
|
|
0.8
|
%
|
|
527
|
|
0.2
|
%
|
|
526
|
|
|
|
Total
territorial
|
|
|
23,067
|
|
|
(1.3
|
)%
|
|
23,364
|
|
0.7
|
%
|
|
23,205
|
|
|
|
Negotiated
Market Sales Tariff (NMST)
|
|
|
1,475
|
|
|
(24.9
|
)%
|
|
1,963
|
|
(6.4
|
)%
|
|
1,845
|
|
|
|
Total
|
|
|
24,542
|
|
|
(3.1
|
)%
|
|
25,327
|
|
1.1
|
%
|
|
25,050
|
|
|
|
•
|
2006
vs 2005
|
Territorial
sales volumes decreased by 307 MWh due to lower industrial sales
volumes
and by 406 MWh due to unfavorable weather. These decreases were partially
offset by 408 MWh due to residential and commercial customer
growth.
|
|
•
|
2005
vs 2004
|
Territorial
sales volumes increased by 407 MWh primarily due to customer growth
partially offset by 261 MWh due to less favorable
weather.
|
Gas
Distribution
Gas
Distribution is comprised of the local distribution operations of SCE&G. Gas
distribution sales margins (including transactions with affiliates) were as
follows:
|
Millions
of dollars
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
||||||||||
|
Operating
revenues
|
|
$
|
504.6
|
|
|
(0.8
|
)%
|
$
|
508.8
|
|
|
28.0
|
%
|
$
|
397.4
|
|
|
|
Less:
Gas purchased for resale
|
|
|
395.5
|
|
|
(5.1
|
)%
|
|
416.6
|
|
|
32.8
|
%
|
|
313.6
|
|
|
|
Margin
|
|
$
|
109.1
|
|
|
18.3
|
%
|
$
|
92.2
|
|
|
10.0
|
%
|
$
|
83.8
|
|
|
|
•
|
2006
vs 2005
|
Margin
increased by $17.5 million due to increased retail gas base rates
which
became effective with the first billing cycle in November 2005 and
by $4.0
million due to an SCPSC approved increase in retail gas base rates
effective with the first billing cycle in November 2006. These increases
were offset by $4.0 million due to lower firm margin resulting from
customer conservation.
|
|
•
|
2005
vs 2004
|
Margin
increased by $4.7 million due to higher firm margin and by $4.6 million
due to increased retail gas base rates which became effective with
the
first billing cycle in November 2005. These increases were offset
by a
$0.8 million decrease due to lower interruptible margin and transportation
revenue.
|
Dekatherm
(DT) sales volumes by class, including transportation gas, were as
follows:
|
Classification
(in thousands)
|
2006
|
%
Change
|
2005
|
% Change
|
2004
|
||
|
Residential
|
10,926
|
(14.7
|
)%
|
12,806
|
(0.9
|
)%
|
12,916
|
|
Commercial
|
11,984
|
(4.5
|
)%
|
12,553
|
3.3
|
%
|
12,155
|
|
Industrial
|
17,879
|
12.4
|
%
|
15,907
|
5.4
|
%
|
15,087
|
|
Transportation
gas
|
2,484
|
22.2
|
%
|
2,032
|
(10.6
|
)%
|
2,272
|
|
Total
|
43,273
|
(0.1
|
)%
|
43,298
|
2.0
|
%
|
42,430
|
|
•
|
2006
vs 2005
|
Residential
and commercial sales volumes decreased primarily due to milder weather
and
conservation. Industrial and transportation sales volumes increased
due to
the competitive position of gas relative to alternate fuel
sources.
|
|
•
|
2005
vs 2004
|
Commercial
and industrial sales volumes increased primarily due to more customers
buying commodity gas instead of purchasing alternate fuels and instead
of
transporting gas purchased from
others.
|
Other
Operating Expenses
Other
operating expenses, which arose from the operating segments previously
discussed, were as follows:
|
Millions
of dollars
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
|||||||||||
|
Other
operation and maintenance
|
|
$
|
460.7
|
|
4.4
|
%
|
$
|
441.2
|
|
|
2.4
|
%
|
$
|
431.0
|
|
|||
|
Depreciation
and amortization
|
|
|
285.8
|
|
(38.5
|
)%
|
|
464.8
|
|
|
*
|
|
220.9
|
|
||||
|
Other
taxes
|
|
|
137.8
|
|
5.2
|
%
|
|
131.0
|
|
|
(0.2
|
)%
|
|
131.3
|
|
|||
|
Total
|
|
$
|
884.3
|
|
(14.7
|
)%
|
$
|
1,037.0
|
|
|
32.4
|
%
|
$
|
783.2
|
|
|||
*
Greater
than 100%
|
•
|
2006 vs 2005
|
Other
operation and maintenance expenses increased by $11.1 million primarily
due to increased electric generation, transmission and distribution
expenses, by $3.1 million due to increased gas distribution expenses,
by
$4.6 million due to lower pension income and other postretirement
benefits
and by $2.0 million due to higher customer service expenses. These
increases were partially offset by $13.9 million due to decreased
incentive compensation expense. Depreciation and amortization expense
decreased by $185.8 million due to lower accelerated depreciation
of the
back-up dam at Lake Murray in 2006 compared to 2005 (see Income Taxes
-Recognition
of Synthetic Fuel Tax Credits),
partially offset by $6.7 million due to property additions and higher
depreciation rates. Other taxes increased primarily due to higher
property
taxes of $6.0 million.
|
|
•
|
2005 vs 2004
|
Other
operation and maintenance expenses increased by $11.5 million due
to
increased electric generation, transmission and distribution expenses,
higher expenses related to regulatory matters of $1.9 million and
higher
amortization of regulatory assets of $3.6 million. The increases
were
offset primarily by decreased long-term bonus and incentive plan
expenses
of $4.8 million and decreased storm damage expenses of $0.9 million.
Depreciation and amortization increased approximately $214.0 million
due
to accelerated depreciation of the back-up dam at Lake Murray (see
Income
Taxes
- Recognition
of Synthetic Fuel Tax Credits),
increased $6.5 million due to the completion of the Jasper County
Electric
Generating Station in May 2004 and increased $6.1 million due to
normal
net property changes. In addition, pursuant to the January 2005 rate
order, SCE&G began amortization of previously deferred purchased power
costs and implemented new depreciation rates, resulting in $17.3
million
of additional depreciation and amortization expense in the
period.
|
Other
Income (Expense)
Other
income (expense) includes the results of certain non-utility activities.
Components of other income (expense), were as follows:
|
Millions
of dollars
|
|
2006
|
% Change
|
2005
|
% Change
|
2004
|
|
|||||||||||
|
Gain
on sale of assets
|
|
$
|
3.0
|
|
76.5
|
%
|
$
|
1.7
|
|
21.4
|
%
|
$
|
1.4
|
|||||
|
Other
revenues
|
|
|
60.8
|
|
(62.4
|
)%
|
162.4
|
|
57.5
|
%
|
|
103.1
|
||||||
|
Other
expenses
|
|
|
(45.1
|
)
|
|
(67.9
|
)%
|
|
(140.7
|
)
|
|
55.1
|
%
|
|
(90.7
|
)
|
||
|
Total
|
|
$
|
18.7
|
|
(20.1
|
)%
|
$
|
23.4
|
|
69.6
|
%
|
$
|
13.8
|
|||||
|
•
|
2006 vs 2005
|
Other
revenues decreased $91.5 million due to lower power marketing activities,
$10.8 million due to the termination of a contract to operate a steam
combustion turbine at the United States Department of Energy (DOE)
Savannah River Site and by $4.3 million due to lower carrying costs
recognized on the unrecovered balance of the Lake Murray back-up
dam
project as discussed at Income Taxes
- Recognition
of Synthetic Fuel Tax Credits
below. These decreases were partially offset by higher interest income
of
$8.7 million and higher third-party coal sales revenue of $4.8
million.
Other
expenses decreased by $90.6 million due to lower power marketing
activities and $4.4 million due to the termination of the DOE’s Savannah
River Site contract. These decreases were partially offset by increased
charges of $8.7 million related to the settlement of the FERC power
marketing matter (see Note 10 to the consolidated financial statements)
and higher expenses to support third-party coal sales of $3.6
million.
|
||||||||||||||||
|
•
|
2005 vs 2004
|
Other
revenues increased $42.8 million due to higher power marketing activity
and $10.9 million due to carrying costs recognized on the unrecovered
balance of the Lake Murray back-up dam project.
Other
expenses increased $43.1 million due to higher power marketing activity
and $.8 million due to the charge associated with the FERC power
marketing
matter. (See Note 10 to the consolidated financial
statements.)
|
Interest
Expense
Components
of interest expense, excluding the debt component of AFC, were as
follows:
|
Millions
of dollars
|
|
2006
|
%
Change
|
2005
|
%
Change
|
2004
|
|
|||||||||||
|
Interest
on long-term debt, net
|
|
$
|
123.9
|
|
(7.1
|
)%
|
$
|
133.3
|
|
|
(0.2
|
)%
|
$
|
135.4
|
|
|||
|
Other
interest expense
|
|
|
16.1
|
|
46.4
|
%
|
|
11.0
|
|
|
*
|
|
3.5
|
|
||||
|
Total
|
|
$
|
140.0
|
|
(3.0
|
)%
|
$
|
144.3
|
|
|
3.9
|
%
|
$
|
138.9
|
|
|||
*
Greater
than 100%
|
•
|
2006 vs 2005
|
Interest
on long-term debt decreased primarily due to lower interest rates
and the
redemption of outstanding debt in 2005. Other interest expense increased
primarily due to higher principal balances and interest rates on
short-term debt.
|
|
•
|
2005 vs 2004
|
Interest
on long-term debt decreased primarily due to the redemption of outstanding
debt. Other interest expense increased primarily due to increased
short-term debt.
|
Income
Taxes
Income
taxes increased approximately $237.6 million for the year 2006 compared to
2005 and decreased approximately $269.9 million for the year 2005 compared
to 2004. Changes in income taxes are primarily due to changes in operating
income, and due to the recognition of $30.0 million in synthetic fuel tax
credits in 2006 compared to $179.0 million in 2005 pursuant to the January
2005
electric rate order. SCE&G’s effective tax rate has been favorably impacted
in recent years by the flow-through of state investment tax credits and the
equity portion of AFC.
Recognition
of Synthetic Fuel Tax Credits
SCE&G
holds equity-method investments in two partnerships involved in converting
coal
to synthetic fuel, the use of which fuel qualifies for federal income tax
credits. Under an accounting plan approved by the Public Service Commission
of
South Carolina (SCPSC) in June 2000, the synthetic fuel tax credits generated
by
the partnerships and passed through to SCE&G, net of partnership losses and
other expenses, were deferred until the SCPSC approved its application to offset
capital costs of the Lake Murray back-up dam project. Under the accounting
methodology approved by the SCPSC in a January 2005 order, construction costs
related to the project were recorded in utility plant in service in a special
dam remediation account outside of rate base, and depreciation is being
recognized against the balance in this account on an accelerated basis, subject
to the availability of the synthetic fuel tax credits.
The
level of
depreciation expense and related tax benefit recognized in the income statement
is equal to the available synthetic fuel tax credits, less partnership losses
and other expenses, net of taxes. As a result, the balance of unrecovered costs
in the dam remediation account declines as accelerated depreciation is recorded.
Although these entries collectively have no impact on consolidated net income,
they have a significant impact on individual line items within the income
statement. The
accelerated depreciation, synthetic fuel tax credits, partnership losses and
the
income tax benefit arising from such losses recognized by SCE&G during 2006
and 2005 are as follows:
|
Millions
of dollars
|
2006
|
2005
|
|||||
|
|
|
|
|||||
|
Depreciation
and amortization expense
|
$
|
(28.2
|
)
|
$
|
(214.0
|
)
|
|
|
|
|||||||
|
Income
tax benefits:
|
|||||||
|
From
synthetic fuel tax credits
|
30.0
|
179.0
|
|||||
|
From
accelerated depreciation
|
10.8
|
81.8
|
|||||
|
From
partnership losses
|
7.8
|
28.9
|
|||||
|
Total
income tax benefits
|
48.6
|
289.7
|
|||||
|
|
|||||||
|
Losses
from Equity Method Investments
|
(20.4
|
)
|
(75.7
|
)
|
|||
|
|
|||||||
|
Impact
on Net Income
|
-
|
-
|
|||||
The
2005
amounts above reflect the recognition of previously deferred tax credits, while
the 2006 amounts reflect the likelihood that credits available in 2006 will
be
phased down pursuant to regulations which limit the credits based on the
relative commodity price of crude oil.
Depreciation
on the Lake Murray back-up dam project account will be matched to available
synthetic fuel tax credits on a quarterly basis until the balance in the dam
remediation account is zero or until all of the available synthetic fuel tax
credits have been utilized. The synthetic fuel tax credit program expires at
the
end of 2007.
The
availability of the synthetic fuel tax credits is dependent on several factors,
one of which is the average annual domestic wellhead price per barrel of crude
oil as published by the U.S. Government. Under a phase-out provision included
in
the program, if the domestic wellhead reference price of oil per barrel for
a
given year is below an inflation-adjusted benchmark range for that year, all
of
the synthetic fuel tax credits that have been generated in that year would
be
available for use. If that price is above the benchmark range, none of the
tax
credits would be available. If that price falls within the benchmark range,
a
calculated portion of the credits would be available.
The
benchmark price range for 2005, published in April 2006, was $53 to $67 per
barrel, and no phase-out applied. However, SCE&G’s analysis indicates that
the available synthetic fuel tax credits for 2006 are likely to be impacted
by
the phase-out calculation. As such, in 2006 the Company recorded synthetic
fuel
tax credits and applied those credits to allow the recording of accelerated
depreciation related to the balance in the dam remediation project account
based
on an estimate that only 67% of credits generated will be available (phase-out
of 33%). The Company cannot predict what impact, if any, the price of oil may
have on the Company’s ability to earn and utilize synthetic fuel tax credits in
the future. However, there is significant uncertainty as to the continued
availability of the credits in 2007. The availability of these synthetic fuel
tax credits is also subject to coal availability and other operational risks
related to the generating plants.
The
Company does not expect available credits to be sufficient to fully recover
the
construction costs of dam remediation, and total unrecovered cost at the end
of
December 31, 2007 may be significant. To the extent that available credits
are
not sufficient to fully recover the construction costs of the dam remediation,
regulatory action to allow recovery of those remaining costs may be sought.
As
of December 31, 2006, remaining unrecovered costs, based on management’s
recording of accelerated depreciation and related tax benefits, were $69.1
million.
LIQUIDITY
AND CAPITAL RESOURCES
The
Company’s cash requirements arise primarily from its operational needs, funding
its construction programs and payment of dividends to SCANA. The ability of
the
Company to replace existing plant investment, to expand to meet future demand
for electricity and gas and to install equipment necessary to comply with
environmental regulations, will depend upon its ability to attract the necessary
financial capital on reasonable terms. SCE&G recovers the costs of providing
services through rates charged to customers. Rates for regulated services are
generally based on historical costs. As customer growth and inflation occur
and
SCE&G continues its ongoing construction program, SCE&G expects to seek
increases in rates. The Company’s future financial position and results of
operations will be affected by SCE&G’s ability to obtain adequate and timely
rate and other regulatory relief, if requested.
SCE&G
expects to require the addition of base load electrical generation by 2015
and
is evaluating alternatives, including fossil and nuclear-fueled generation
facilities. In February 2006, SCE&G and the South Carolina Public Service
Authority (Santee Cooper), a state-owned utility in South Carolina (joint owners
of V. C. Summer Nuclear Station (Summer Station)), announced their selection
of
the Summer Station site as the preferred site for new nuclear generation
facilities should such generation be considered the best alternative in the
future. Due to the significant lead time required for construction of nuclear
generation facilities, the joint owners are preparing an application to the
United States Nuclear Regulatory Commission (NRC) for a combined construction
and operating license (COL) that would cover two nuclear units. The COL
application, which is expected to be completed and filed in 2007, would be
reviewed by the NRC for an estimated three years. Issuance of a COL would not
obligate the joint owners to build nuclear generation facilities. The final
decision to build nuclear generation facilities will be influenced by several
factors, including NRC licensing attainment, estimates of construction and
operating costs, the cost of competing fuels, regulatory and environmental
requirements and financial market conditions.
The
Company’s current estimates of its capital expenditures for construction and
nuclear fuel for 2007-2009, which are subject to continuing review and
adjustment, are as follows:
Estimated
Capital Expenditures
|
Millions
of dollars
|
|
2007
|
2008
|
2009
|
|
|||||
|
|
|
|
||||||||
|
SCE&G:
|
|
|
|
|
|
|
|
|||
|
Electric
Plant:
|
|
|
|
|
|
|
|
|||
|
Generation
(including GENCO)
|
|
$
|
220
|
|
$
|
361
|
$
|
255
|
|
|
|
Transmission
|
|
|
45
|
|
|
52
|
35
|
|
||
|
Distribution
|
|
|
151
|
|
|
155
|
153
|
|
||
|
Other
|
|
|
28
|
|
|
38
|
17
|
|
||
|
Nuclear
Fuel
|
|
|
55
|
|
|
6
|
26
|
|
||
|
Gas
|
|
|
50
|
|
|
59
|
52
|
|
||
|
Common
and Other
|
|
|
28
|
|
|
10
|
12
|
|
||
|
Total
|
|
$
|
577
|
|
$
|
681
|
$
|
550
|
|
|
The
Company’s contractual cash obligations as of December 31, 2006 are
summarized as follows:
Contractual
Cash Obligations
|
Millions
of dollars
|
|
Total
|
Less
than
1
year
|
1-3
years
|
4-5
years
|
After
5
years
|
|
|||||||||
|
Long-term
and short-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
(including
interest and preferred stock)
|
|
$
|
4,559
|
|
$
|
493
|
|
$
|
499
|
|
$
|
377
|
|
$
|
3,190
|
|
|
Capital
leases
|
|
|
2
|
|
|
1
|
|
|
1
|
|
|
-
|
|
|
-
|
|
|
Operating
leases
|
|
|
49
|
|
|
27
|
|
|
22
|
|
|
-
|
|
|
-
|
|
|
Purchase
obligations
|
|
|
278
|
|
|
199
|
|
|
76
|
|
|
2
|
|
|
1
|
|
|
Other
commercial commitments
|
|
|
1,432
|
|
|
490
|
|
|
821
|
|
|
29
|
|
|
92
|
|
|
Total
|
|
$
|
6,320
|
|
$
|
1,210
|
|
$
|
1,419
|
|
$
|
408
|
|
$
|
3,283
|
|
Included
in other commercial commitments are estimated obligations for coal and nuclear
fuel purchases. See Note 10 to the consolidated financial
statements.
Included
in purchase obligations are customary purchase orders under which SCE&G has
the option to utilize certain vendors without the obligation to do so. SCE&G
may terminate such obligations without penalty.
The
Company also has a legal obligation associated with the decommissioning and
dismantling of Summer Station and other conditional asset retirement obligations
that are not listed in the contractual cash obligations above. See Notes 1B
and 10H to the consolidated financial statements.
In
addition to the contractual cash obligations above, SCANA sponsors a
noncontributory defined benefit pension plan and an unfunded health care and
life insurance benefit plan for retirees. The pension plan is adequately funded,
and no further contributions are anticipated until after 2010. The Company’s
cash payments under the health care and life insurance benefit plan were
$7.3 million in 2006, and such annual payments are expected to increase to
the $10-$11 million range in the future.
The
Company anticipates that its contractual cash obligations will be met through
internally generated funds, the incurrence of additional short-term and
long-term indebtedness and capital contributions from its parent, SCANA. The
Company expects that it has or can obtain adequate sources of financing to
meet
its projected cash requirements for the foreseeable future.
Cash
outlays for 2006 (actual) and 2007 (estimated) for certain expenditures are
as
follows:
|
Millions
of dollars
|
2006
|
2007
|
|||||
|
Property
additions and construction expenditures, net of AFC
|
|
$
|
412
|
|
$
|
522
|
|
|
Nuclear
fuel expenditures
|
|
|
17
|
|
|
55
|
|
|
Investments
|
|
|
22
|
|
|
19
|
|
|
Total
|
|
$
|
451
|
|
$
|
596
|
|
Financing
Limits and Related Matters
The
Company’s issuance of various securities, including long-term and short-term
debt, is subject to customary approval or authorization by regulatory bodies
including the SCPSC and FERC. Financing programs currently utilized by the
Company are as follows.
Pursuant
to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC
authority to issue short-term debt. Effective February 8, 2006 the FERC has
authorized SCE&G and GENCO to issue up to $700 million and $100 million,
respectively, of unsecured promissory notes or commercial paper with maturity
dates of one year or less. This authorization expires February 7,
2008.
At
December 31, 2006, SCE&G and Fuel Company had available the following
lines of credit and short-term borrowings outstanding:
|
|
|
Millions
of dollars
|
|
|
|
Lines
of credit (total and unused):
|
|
|
|
|
|
SCE&G
and Fuel Company
|
|
|
|
|
|
Committed
long-term (expires December 2011)
|
|
$
|
650
|
|
|
Uncommitted
(a)
|
|
|
78
|
|
|
Short-term
borrowings outstanding:
|
|
|
||
|
Commercial
paper (270 or fewer days)
|
|
$
|
362.2
|
|
|
Weighted
average interest rate
|
|
|
5.38
|
%
|
(a)
Line
of credit that either SCE&G or SCANA may use.
In
September 2006 SCE&G discharged its bond indenture dated January 1,
1945 which covered substantially all of its properties. SCE&G remains
subject to a bond indenture dated April 1, 1993 (Mortgage) covering
substantially all of its electric properties under which all of its currently
outstanding First Mortgage Bonds and all of its future mortgage-backed debt
(Bonds) has been and will be issued. Bonds may be issued under the Mortgage
in
an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded
Net
Property Additions (as therein defined), (2) the aggregate principal amount
of
retired Bonds and (3) cash deposited with the trustee. Bonds will be issuable
under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12
consecutive months out of the 18 months immediately preceding the month of
issuance are at least twice the annual interest requirements on all outstanding
Bonds and Bonds to be outstanding (Bond Ratio). For the year ended
December 31, 2006, the Bond Ratio was 6.99.
SCE&G’s
Restated Articles of Incorporation (Articles) prohibit issuance of additional
shares of preferred stock without the consent of the preferred shareholders
unless net earnings (as therein defined) for the 12 consecutive months
immediately preceding the month of issuance are at least one and one-half times
the aggregate of all interest charges and preferred stock dividend requirements
on all shares of preferred stock outstanding immediately after the proposed
issue (Preferred Stock Ratio). For the year ended December 31, 2006, the
Preferred Stock Ratio was 1.99.
The
Articles also require the consent of a majority of the total voting power of
SCE&G’s preferred stock before SCE&G may issue or assume any unsecured
indebtedness if, after such issue or assumption, the total principal amount
of
all such unsecured indebtedness would exceed ten percent of the aggregate
principal amount of all of SCE&G’s secured indebtedness and capital and
surplus (the ten percent test). No such consent is required to enter into
agreements for payment of principal, interest and premium for securities issued
for pollution control purposes. At December 31, 2006, the ten percent test
would have limited total issuances of unsecured indebtedness to approximately
$428.4 million. Unsecured indebtedness at December 31, 2006, totaled
approximately $357.8 million, and was comprised primarily of short-term
borrowings.
Financing
Cash Flows
During
2006 the Company experienced net cash outflows related to financing activities
of approximately $38 million primarily due to the payment of dividends to
SCANA, which were partially offset by net increases in short-term
borrowings.
In
anticipation of the issuance of debt, the Company may use interest rate lock
or
similar agreements to manage interest rate risk. Payments received or made
upon
termination of such agreements are recorded within long-term debt on the balance
sheet and are amortized to interest expense over the term of the underlying
debt. In connection with the issuance of first mortgage bonds in June 2006,
SCE&G received approximately $8.8 million upon the termination of an
interest rate lock. These proceeds are being amortized over the life of the
related debt, thereby reducing its effective interest rate. As permitted by
SFAS
104 “Statement
of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and
Classification of Cash Flows from Hedging Transactions,” these
proceeds have been classified as a financing activity in the consolidated
statement of cash flows.
For
additional information on significant financing transactions, see Note 4 to
the Company’s consolidated financial statements.
ENVIRONMENTAL
MATTERS
Capital
Expenditures
For
the
three years ended December 31, 2006, the Company’s capital expenditures for
environmental control totaled $160.2 million. These expenditures were in
addition to environmental expenditures included in “Other operation and
maintenance” expenses, which were $28.1 million, $25.2 million, and
$21.3 million during 2006, 2005 and 2004, respectively. It is not possible
to estimate all future costs related to environmental matters, but forecasts
for
capitalized environmental expenditures for the Company are $154.6 million
for 2007 and $494.6 million for the four-year period 2008 through 2011.
These expenditures are included in the Company’s construction program discussed
in Liquidity and Capital Resources, and include the matters discussed
below.
Electric
Operations
In
March
2005, the United States Environmental Protection Agency (EPA) issued a final
rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District
of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide
and sulfur dioxide emissions in order to attain mandated state levels. SCE&G
has petitioned the United States Court of Appeals for the District of Columbia
Circuit to review CAIR. Several other electric utilities have filed separate
petitions. The petitioners seek a change in the method CAIR uses to allocate
sulfur dioxide emission allowances to a method the petitioners believe is more
equitable. The Company believes that installation of additional air quality
controls will be needed to meet the CAIR requirements. The Company is reviewing
the final rule. Compliance plans and cost to comply with the rule will be
determined once the Company completes its review. Such costs will to be material
and are expected to be recoverable through rates.
In
March
2005, the EPA issued a final rule establishing a mercury emissions cap and
trade
program for coal-fired power plants that requires limits to be met in two
phases, in 2010 and 2018. Although
the Company expects to be able to meet the Phase I limits through those measures
it already will be taking to meet its CAIR obligations, it is uncertain as
to
how the Phase II limits will be met. Assuming Phase II limits remain unchanged,
installation of additional air quality controls likely will be required to
comply with the rule’s Phase II mercury emission caps. Final compliance plans
and costs to comply with the rule are still under review. Such costs will be
material and are expected to be recoverable through rates.
The
EPA
has undertaken an aggressive enforcement initiative against the utilities
industry, and the United States Department of Justice (DOJ) has brought suit
against a number of utilities in federal court alleging violations of the Clean
Air Act (CAA). At least two of these suits have either been tried or have had
substantive motions decided—one favorable to the industry and one not. The one
not favorable to the industry is not binding as precedent and the one favorable
to the industry likely is precedent and is consistent with current Company
interpretation of the law and its resulting maintenance practices. Prior to
the
suits, those utilities had received requests for information under
Section 114 of the CAA and were issued Notices of Violation. The basis for
these suits is the assertion by the EPA, under a stringent rule known as New
Source Review (NSR), that maintenance activities undertaken by the utilities
over the past 20 or more years constitute “major modifications” which would have
required the installation of costly Best Available Control Technology (BACT).
SCE&G and GENCO have received and responded to Section 114 requests for
information related to Canadys, Wateree and Williams Stations. The regulations
under the CAA provide certain exemptions to the definition of “major
modifications,” including an exemption for routine repair, replacement or
maintenance. On October 27, 2003, EPA published a final revised NSR rule in
the Federal Register with an effective date of December 26, 2003. The rule
represents an industry-favorable departure from certain positions advanced
by
the federal government in the NSR enforcement initiative. However, on motion
of
several Northeastern states, the United States Circuit Court of Appeals for
the
District of Columbia stayed the effect of the final rule. The ultimate
application of the final rule to the Company is uncertain. The Company has
analyzed each of the activities covered by the EPA’s requests and believes each
of these activities is covered by the exemption for routine repair, replacement
and maintenance under what it believes is a fair reading of both the prior
regulation and the contested revised regulation. The regulations also provide
an
exemption for an increase in emissions resulting from increased hours of
operation or production rate and from demand growth.
The
current state of continued DOJ enforcement actions is the subject of
industry-wide speculation, but it is possible that the EPA will commence
enforcement actions against the Company, and the EPA has the authority to seek
penalties at the rate of up to $27,500 per day for each violation. The EPA
also
could seek installation of BACT (or equivalent) at the three plants. The Company
believes that any enforcement actions relative to the Company’s compliance with
the CAA would be without merit. The Company has completed installation of
selective catalytic reactors at Wateree and Williams for nitrogen oxides control
and is proceeding with plans to install sulfur dioxide scrubbers at both of
these stations to meet CAIR regulations. These actions would mitigate many
of
the concerns with NSR. The Company expects to incur capital expenditures
totaling approximately $450 million over the 2007-2010 period to install
this new equipment. The Company expects to have increased operation and
maintenance costs of approximately $4 million in 2010 and $27 million in
2011 and subsequent years. To meet compliance requirements for the years 2012
through 2016, the Company anticipates additional capital expenditures totaling
approximately $480 million.
The
Clean
Water Act, as amended, provides for the imposition of effluent limitations
that
require treatment for wastewater discharges. Under the Clean Water Act,
compliance with applicable limitations is achieved under a national permit
program. Discharge permits have been issued for all, and renewed for nearly
all,
of SCE&G’s and GENCO’s generating units. Concurrent with renewal of these
permits, the permitting agency has implemented a more rigorous program of
monitoring and controlling discharges, has modified the requirements for cooling
water intake structures, and has required strategies for toxicity reduction
in
wastewater streams. The Company is conducting studies and is developing or
implementing compliance plans for these initiatives. Congress is expected to
consider further amendments to the Clean Water Act. Such legislation may include
limitations to mixing zones and toxicity-based standards. These provisions,
if
passed, could have a material adverse impact on the financial condition, results
of operations and cash flows of the Company.
The
Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) required that the United
States government, by January 31, 1998, accept and permanently dispose of
high-level radioactive waste and spent nuclear fuel. The Nuclear Waste Act
also
imposed on utilities the primary responsibility for storage of their spent
nuclear fuel until the repository is available. SCE&G entered into a
Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste (Standard Contract) with the DOE in 1983 providing for
permanent disposal of its spent nuclear fuel in exchange for agreed payments
fixed in the Standard Contract at particular amounts. On January 28, 2004,
SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in
the Court of Federal Claims against the DOE for breach of the Standard Contract,
because as of the date of filing, the federal government had accepted no spent
fuel from Summer Station or any other utility for transport and disposal, and
has indicated that it does not anticipate doing so until 2010, at the earliest.
As a consequence of the federal government’s breach of contract, the plaintiffs
have incurred and will continue to incur substantial costs. On January 9, 2006,
SCE&G and Santee Cooper accepted a $9 million settlement from DOE. The
payment reimbursed the plaintiffs for certain costs incurred from January 31,
1998 through July 31, 2005. SCE&G recorded its portion ($6 million) of the
settlement as a reduction to its fuel costs. As a result, most of the credit
was
passed through to its customers through the fuel clause component of its retail
electric rates. The settlement also provides for the plaintiffs to submit an
annual application to DOE for the reimbursement of certain costs incurred
subsequent to July 31, 2005. SCE&G has on-site spent nuclear fuel storage
capability until at least 2018 and expects to be able to expand its storage
capacity to accommodate the spent nuclear fuel output for the life of the plant
through dry cask storage or other technology as it becomes
available.
SCE&G
has been named, along with 29 others, by the EPA as a potentially responsible
party (PRP) at the Carolina Transformer Superfund site located in Fayetteville,
North Carolina. The Carolina Transformer Company (CTC) conducted an
electrical transformer rebuilding and repair operation at the site from 1967
to
1984. During that time, SCE&G occasionally used CTC for the repair of
existing transformers, purchase of new transformers and sale of used
transformers. In 1984, EPA initiated a cleanup of PCB-contaminated soil
and groundwater at the site. EPA reports that it has spent $36 million to
date. Although a basis for the allocation of clean-up costs among the PRPs
is unclear, SCE&G does not believe that its involvement at this site would
result in an allocation of costs that would have a material adverse impact
on
its results of operations, cash flows or financial condition. Any cost allocated
to SCE&G arising from the remediation of this site, net of insurance
recoveries, if any, is expected to be recoverable through rates.
SCE&G
has been named, along with 53 others, by the EPA as a PRP at the Alternate
Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.
The EPA placed the site on the National Priorities List on April 19, 2006.
AER
conducted hazardous waste storage and treatment operations from 1975 to 2000,
when the site was abandoned. While operational, AER processed fuels from
waste oils, treated industrial coolants and oil/water emulsions, recycled
solvents and blended hazardous waste fuels. During that time, SCE&G
occasionally used AER for the processing of waste solvents, oily rags and oily
wastewater. EPA and the State of Georgia have documented that a release or
releases have occurred at the site leading to contamination of groundwater,
surface water and soils. EPA and the State of Georgia have conducted a
preliminary assessment and site inspection. The site has not been cleaned up
nor
has a cleanup cost been estimated. Although a basis for the allocation of
clean-up costs among the PRPs is unclear, SCE&G does not believe that its
involvement at this site would result in an allocation of costs that would
have
a material adverse impact on its results of operations, cash flows or financial
condition. Any cost allocated to SCE&G arising from the remediation of this
site, net of insurance recoveries, if any, is expected to be recoverable through
rates.
Gas
Distribution
The
Company maintains an environmental assessment program to identify and evaluate
current and former operations sites that could require environmental cleanup.
As
site assessments are initiated, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures may differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations and are recorded in deferred
debits and amortized with recovery provided through rates. Deferred amounts,
net
of amounts previously recovered through rates and insurance settlements, totaled
$17.9 million and $17.7 million at December 31, 2006 and 2005,
respectively. The deferral includes the estimated costs associated with the
following matters.
SCE&G
owns a decommissioned MGP site in the Calhoun Park area of Charleston, South
Carolina. SCE&G anticipates that remediation for contamination at the site
will be completed in late 2007, with certain monitoring and retreatment
activities continuing until 2011. As of December 31, 2006, SCE&G has
spent $22.3 million to remediate the Calhoun Park site, and expects to spend
an
additional $1.1 million. In addition, the National Park Service of the
Department of the Interior made an initial demand to SCE&G for payment of
$9.1 million for certain costs and damages relating to this site. SCE&G
expects to recover any cost arising from the remediation of this site through
rates.
SCE&G
owns three other decommissioned MGP sites in South Carolina which contain
residues of by-product chemicals. One of the sites has been remediated and
will
undergo routine monitoring until released by DHEC. The other sites are currently
being investigated under work plans approved by DHEC. SCE&G anticipates that
major remediation activities for the three sites will be completed in 2011.
As
of December 31, 2006, SCE&G has spent $4.8 million related to
these three sites, and expects to spend an additional $11.2 million. SCE&G
expects to recover any cost arising from the remediation of this site through
rates.
REGULATORY
MATTERS
See
earlier discussion of increases in retail electric and gas base rates during
2006 in Liquidity and Capital Resources.
The
Natural Gas Stabilization Act of 2005 allows natural gas distribution companies
to request annual adjustments to rates to reflect changes in revenues and
expenses and changes in investment. Such annual adjustments are subject to
certain qualifying criteria and review by the SCPSC.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
Following
are descriptions of the Company’s accounting policies and estimates which are
most critical in terms of reporting financial condition or results of
operations.
Utility
Regulation
The
Company is subject to the provisions of SFAS 71, “Accounting
for the Effects of Certain Types of Regulation,”
which
requires it to record certain assets and liabilities that defer the recognition
of expenses and revenues to future periods as a result of being rate-regulated.
In the future, as a result of deregulation or other changes in the regulatory
environment, the Company may no longer meet the criteria for continued
application of SFAS 71 and could be required to write off its regulatory
assets and liabilities. Such an event could have a material adverse effect
on
the results of operations or financial position of the Company’s Electric
Distribution and Gas Distribution segments in the period the write-off would
be
recorded. It is not expected that cash flows would be materially affected.
See
Note 1 to the consolidated financial statements for a description of the
Company’s regulatory assets and liabilities, including those associated with the
Company’s environmental assessment program.
The
Company’s generation assets would be exposed to considerable financial risks in
a deregulated electric market. If market prices for electric generation do
not
produce adequate revenue streams and the enabling legislation or regulatory
actions do not provide for recovery of the resulting stranded costs, the Company
could be required to write down its investment in those assets. The Company
cannot predict whether any write-downs will be necessary and, if they are,
the
extent to which they would adversely affect the Company’s results of operations
in the period in which they would be recorded. As of December 31, 2006, the
Company’s net investments in fossil/hydro and nuclear generation assets were
$2.3 billion and $506 million, respectively.
Revenue
Recognition and Unbilled Revenues
Revenues
related to the sale of energy are recorded when service is rendered or when
energy is delivered to customers. Because customers are billed on cycles which
vary based on the timing of the actual reading of their electric and gas meters,
the Company records estimates for unbilled revenues at the end of each reporting
period. Such unbilled revenue amounts reflect estimates of the amount of energy
delivered to customers since the date of the last reading of their meters.
Such
unbilled revenues reflect consideration of estimated usage by customer class,
the effects of different rate schedules, changes in weather and, where
applicable, the impact of weather normalization provisions of rate structures.
The accrual of unbilled revenues in this manner properly matches revenues and
related costs. As of December 31, 2006 and 2005, accounts receivable
included unbilled revenues of $91.7 million and $99.7 million, respectively,
compared to total revenues for each of the years 2006 and 2005 of
$2.4 billion.
Nuclear
Decommissioning
Accounting
for decommissioning costs for nuclear power plants involves significant
estimates related to costs to be incurred many years in the future. Among the
factors that could change the Company’s accounting estimates related to
decommissioning costs are changes in technology, changes in regulatory and
environmental remediation requirements, and changes in financial assumptions
such as discount rates and timing of cash flows. Changes in any of these
estimates could significantly impact the Company’s financial position and cash
flows (although changes in such estimates should be earnings-neutral, because
these costs are expected to be collected from ratepayers).
SCE&G’s
two-thirds share of estimated site-specific nuclear decommissioning costs for
Summer Station, including both the cost of decommissioning plant components
that
are and are not subject to radioactive contamination, totals
$451.0 million, stated in 2006 dollars, based on a decommissioning study
completed in 2006. Santee Cooper is responsible for decommissioning costs
related to its one-third ownership interest in Summer Station. The cost estimate
assumes that the site would be maintained over a period of 60 years in such
a manner as to allow for subsequent decontamination that would permit release
for unrestricted use.
Under
SCE&G’s method of funding decommissioning costs, amounts collected through
rates are invested in insurance policies on the lives of certain Company
personnel. SCE&G transfers to an external trust fund the amounts collected
through electric rates, insurance proceeds, and interest on proceeds, less
expenses. The trusteed asset balance reflects the net cash surrender value
of
the insurance policies held by the trust. Management intends for the fund,
including earnings thereon, to provide for all eventual decommissioning
expenditures on an after-tax basis.
Accounting
for Pensions and Other Postretirement Benefits
SCANA
follows SFAS 87, “Employers’
Accounting for Pensions,”
as
amended by SFAS 158, in accounting for the cost of its defined benefit pension
plan. SCANA’s plan is adequately funded and as such, net pension income is
reflected in the financial statements (see Results of Operations). SFAS 87
requires the use of several assumptions, the selection of which may have a
large
impact on the resulting benefit recorded. Among the more sensitive assumptions
are those surrounding discount rates and expected returns on assets. Net pension
income of $15.8 million recorded in 2006 reflects the use of a 5.60%
discount rate and an assumed 9.00% long-term rate of return on plan assets.
SCANA believes that these assumptions were, and that the resulting pension
income amount was, reasonable. For purposes of comparison, using a discount
rate
of 5.35% in 2006 would have decreased the Company’s share of SCANA’s pension
income by $0.9 million. Had the assumed long-term rate of return on assets
been 8.75%, the Company’s share of SCANA’s pension income for 2006 would have
been reduced by $2.1 million.
For
2006,
SCANA selected the discount rate of 5.60% which was derived using a cash flow
matching technique. For 2007, the discount rate to be used will be 5.85%, which
was derived using that same cash flow matching technique. The same discount
rates were also selected for determination of other postemployment benefits
costs discussed below.
The
following information with respect to pension assets (and returns thereon)
should also be noted.
SCANA
determines the fair value of substantially all of its pension assets utilizing
market quotes rather than utilizing any calculated values, “market related”
values or other modeling techniques.
In
developing the expected long-term rate of return assumptions, SCANA evaluates
input from actuaries and from pension fund investment consultants. Such
consultants’ 2006 review of the plan’s historical 10, 15, 20 and 25 year
cumulative performance showed actual returns of 9.3%, 11.0%, 11.2% and 12.7%,
respectively, all of which have been in excess of related broad indices. The
2006 expected long-term rate of return of 9.0% was based on a target asset
allocation of 70% with equity managers and 30% with fixed income managers.
Management regularly reviews such allocations and periodically rebalances the
portfolio when considered appropriate. For 2007, the expected rate of return
will be 9.00%.
The
pension trust is adequately funded, and no contributions have been required
since 1997. Management does not anticipate the need to make pension
contributions until after 2010.
Similar
to its pension accounting, SCANA follows SFAS 106, “Employers’
Accounting for Postretirement Benefits Other Than Pensions,”
as
amended by SFAS 158, in accounting for the cost of its postretirement medical
and life insurance benefits. This plan is unfunded, so no assumptions related
to
rate of return on assets impact the net expense recorded; however, the selection
of discount rates can significantly impact the actuarial determination of net
expense. SCANA used a discount rate of 5.60% and recorded a net SFAS 106
cost of $16.8 million for 2006. Had the selected discount rate been 5.35%,
the expense for 2006 would have been $0.4 million higher. The Company also
adopted the balance sheet recognition provisions of SFAS 158 effective December
31, 2006, as more fully described in Note 3 to the consolidated financial
statements. Because the plan provisions include “caps” on company per capita
costs, healthcare cost inflation rate assumptions do not materially impact
the
net expense recorded.
The
Company also adopted the balance sheet recognition provisions of SFAS 158
effective December 31, 2006, as more fully described in Note 3 to the
consolidated financial statements.
Asset
Retirement Obligations
SFAS 143,
“Accounting
for Asset Retirement Obligations,”
together
with FIN 47, provides guidance for recording and disclosing liabilities related
to future legally enforceable obligations to retire assets (ARO). SFAS 143
applies to the legal obligation associated with the retirement of long-lived
tangible assets that result from their acquisition, construction, development
and normal operation. Because such obligation relates to the Company’s regulated
utility operations, SFAS 143 and FIN 47 have no impact on results of
operations. As of December 31, 2006, the Company has recorded an ARO of
approximately $93 million for nuclear plant decommissioning (as discussed above)
and an ARO of $186 million for other conditional obligations related to
generation, transmission and distribution properties, including gas pipelines.
The ARO for nuclear plant decommissioning reflects a reduction of $46 million
from the corresponding ARO recorded as of December 31, 2005. The reduction
is
primarily related to the expectation of lower decommissioning cost escalations
than had been assumed in the prior cash flow analysis. All of the amounts
recorded in connection with SFAS 143 and FIN 47 are based upon estimates which
are subject to varying degrees of imprecision, particularly since such payments
will be made many years in the future. Changes in these estimates will be
recorded over time; however, these changes in estimates are not expected to
materially impact results of operations so long as the regulatory framework
for
the Company’s utilities remains in place.
OTHER
MATTERS
Off-Balance
Sheet Financing
SCE&G
does not hold investments in unconsolidated special purpose entities such as
those described in SFAS 140, “Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities,”
or as
described in FIN 46(R), “Consolidation
of Variable Interest Entities.”
SCE&G does not engage in off-balance sheet financing or similar
transactions, although it is party to incidental operating leases in the normal
course of business, generally for office space, furniture and
equipment.
Claims
and Litigation
For
a
description of claims and litigation see Item 3. LEGAL PROCEEDINGS and
Note 10 to the consolidated financial statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All
financial instruments held by SCE&G described below are held for purposes
other than trading.
The
tables below summarize long-term debt issued by SCE&G which is sensitive to
changes in interest rates. For debt obligations, the tables present principal
cash flows and related weighted average interest rates by expected maturity
dates. Fair values for debt represent quoted market prices.
|
|
Expected
Maturity Date
|
|||||||
|
December 31,
2006
Millions
of dollars
|
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter
|
Total
|
Fair
Value
|
|
Long-Term
Debt:
|
|
|
|
|
|
|
|
|
|
Fixed
Rate ($)
|
3.7
|
3.7
|
103.7
|
10.4
|
164.9
|
1,667.9
|
1,954.3
|
2,001.2
|
|
Average
Interest Rate (%)
|
7.78
|
7.78
|
6.18
|
6.31
|
6.70
|
5.83
|
5.93
|
|
|
|
Expected
Maturity Date
|
|||||||
|
December 31,
2005
Millions
of dollars
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
Total
|
Fair
Value
|
|
Long-Term
Debt:
|
|
|
|
|
|
|
|
|
|
Fixed
Rate ($)
|
169.9
|
39.2
|
39.2
|
139.2
|
39.2
|
1,714.4
|
2,141.1
|
2,051.3
|
|
Average
Interest Rate (%)
|
8.51
|
6.86
|
6.86
|
6.33
|
6.86
|
5.88
|
6.17
|
|
While
a
decrease in interest rates would increase the fair value of debt, it is unlikely
that events which would result in a realized loss will occur.
The
above
table excludes long-term debt of $80 million at December 31, 2006 and
$97 million at December 31, 2005, which amounts do not have a stated
interest rate associated with them.
Commodity
Price Risk
The
following table summarizes the Company’s financial instruments that are
sensitive to changes in natural gas prices. Weighted average settlement prices
are per 10,000 DT. Fair value represents quoted market prices.
|
Expected
Maturity:
|
|
|
|
|
|
|||
|
|
Futures
Contracts
|
||
|
2007
|
Long
|
Short
|
|
|
|
|
|
|
|
Settlement
Price (a)
|
6.82
|
6.61
|
|
|
Contract
Amount (b)
|
28.6
|
2.9
|
|
|
Fair
Value (b)
|
21.8
|
2.0
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
Settlement
Price (a)
|
8.46
|
-
|
|
|
Contract
Amount (b)
|
5.2
|
-
|
|
|
Fair
Value (b)
|
4.9
|
-
|
|
|
|
|
|
|
|
(a)
Weighted average, in dollars
|
|
|
|
|
(b)
Millions of dollars
|
|||
|
Expected
Maturity
|
||
|
Commodity
Swaps
|
2007
|
2008
|
|
|
|
|
|
Commodity
Swaps:
|
|
|
|
Pay
fixed/receive variable (b)
|
53.7
|
32.6
|
|
Average
pay rate (a)
|
8.8558
|
8.7337
|
|
Average
received rate (a)
|
7.1309
|
8.3193
|
|
Fair
value (b)
|
43.3
|
31.1
|
|
|
|
|
|
(a)
Weighted average, in dollars
|
|
|
|
(b)
Millions of dollars
|
||
The
Company uses derivative instruments to hedge forward purchases and sales of
natural gas, which create market risks of different types. See Note 9 to
the consolidated financial statements.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
South
Carolina Electric & Gas Company:
We
have
audited the accompanying consolidated balance sheets of South Carolina Electric
& Gas Company and affiliates (the “Company”) as of December 31, 2006 and
2005, and the related consolidated statements of income, changes in common
equity, and of cash flows for each of the three years in the period ended
December 31, 2006. Our audits also included the financial statement schedule
listed in Part IV at Item 15. 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 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. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As
discussed in Note 3 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans,”
effective December 31, 2006.
In
our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of South Carolina Electric & Gas Company
and affiliates at December 31, 2006 and 2005 and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2006, in conformity with accounting principles generally accepted in the
United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
/s/Deloitte
& Touche LLP
Columbia,
South Carolina
February
28, 2007
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED
BALANCE SHEETS
|
December 31,
(Millions of dollars)
|
|
2006
|
2005
|
|
|||
|
Assets
|
|
|
|
|
|
||
|
Utility
Plant In Service:
|
|
$
|
7,876
|
$
|
7,687
|
|
|
|
Accumulated
Depreciation and Amortization
|
|
|
(2,483
|
)
|
|
(2,295
|
)
|
|
|
|
|
5,393
|
|
5,392
|
|
|
|
Construction
Work in Progress
|
|
|
316
|
|
160
|
|
|
|
Nuclear
Fuel, Net of Accumulated Amortization
|
|
|
39
|
|
28
|
|
|
|
Utility Plant, Net
|
|
|
5,748
|
|
5,580
|
|
|
|
Nonutility
Property and Investments:
|
|
|
|
|
|
||
|
Nonutility property, net of accumulated depreciation
|
|
|
31
|
|
28
|
|
|
|
Assets held in trust, net-nuclear decommissioning
|
|
|
56
|
|
52
|
|
|
|
Other investments
|
|
|
25
|
|
28
|
|
|
|
Nonutility Property and Investments, Net
|
|
|
112
|
|
108
|
|
|
|
Current
Assets:
|
|
|
|
|
|
||
|
Cash and cash equivalents
|
|
|
24
|
|
19
|
|
|
|
Receivables, net of allowance for uncollectible accounts of $5
and $2
|
|
|
311
|
|
366
|
|
|
|
Receivables-affiliated companies
|
|
|
41
|
|
32
|
|
|
|
Inventories (at average cost):
|
|
|
|
|
|
||
|
Fuel
|
|
|
147
|
|
62
|
|
|
|
Materials and supplies
|
|
|
85
|
|
72
|
|
|
|
Emission allowances
|
|
|
22
|
|
54
|
|
|
|
Prepayments
and other
|
|
|
20
|
|
12
|
|
|
|
Deferred income taxes
|
|
|
19
|
|
22
|
|
|
|
Total Current Assets
|
|
|
669
|
|
639
|
|
|
|
Deferred
Debits:
|
|
|
|
|
|
||
|
Pension asset, net
|
|
|
200
|
|
303
|
|
|
|
Due from affiliates-pension and benefits
|
|
|
41
|
|
31
|
|
|
|
Emission allowances
|
27
|
-
|
|||||
|
Regulatory assets
|
|
|
702
|
|
584
|
|
|
|
Other
|
|
|
127
|
|
121
|
|
|
|
Total Deferred Debits
|
|
|
1,097
|
|
1,039
|
|
|
|
Total
|
|
$
|
7,626
|
$
|
7,366
|
|
|
|
December
31, (Millions of dollars)
|
|
2006
|
2005
|
|
|||
|
Capitalization
and Liabilities
|
|
|
|
|
|
||
|
Shareholders’
Investment:
|
|
|
|
|
|
||
|
Common equity
|
|
$
|
2,457
|
|
$
|
2,362
|
|
|
Preferred stock (Not subject to purchase or sinking funds)
|
|
|
106
|
|
|
106
|
|
|
Total Shareholders’ Investment
|
|
|
2,563
|
|
|
2,468
|
|
|
Preferred
Stock, net (Subject to purchase or sinking funds)
|
|
|
8
|
|
|
8
|
|
|
Long-Term
Debt, net
|
|
|
2,008
|
|
|
1,856
|
|
|
Total
Capitalization
|
|
|
4,579
|
|
|
4,332
|
|
|
Minority
Interest
|
|
|
86
|
|
|
82
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Short-term borrowings
|
|
|
362
|
|
|
303
|
|
|
Current portion of long-term debt
|
|
|
14
|
|
|
183
|
|
|
Accounts payable
|
|
|
155
|
|
|
84
|
|
|
Accounts payable—affiliated companies
|
|
|
147
|
|
|
142
|
|
|
Customer deposits and customer prepayments
|
|
|
40
|
|
|
35
|
|
|
Taxes accrued
|
|
|
112
|
|
|
140
|
|
|
Interest
accrued
|
|
|
33
|
|
|
35
|
|
|
Dividends declared
|
|
|
23
|
|
|
40
|
|
|
Other
|
|
|
63
|
|
|
38
|
|
|
Total Current Liabilities
|
|
|
949
|
|
|
1,000
|
|
|
Deferred
Credits:
|
|
|
|
|
|
|
|
|
Deferred income taxes, net
|
|
|
807
|
|
|
801
|
|
|
Deferred investment tax credits
|
|
|
118
|
|
|
119
|
|
|
Asset retirement obligations
|
|
|
279
|
|
|
309
|
|
|
Postretirement benefits
|
|
|
194
|
|
|
148
|
|
|
Due to affiliates-pension and benefits
|
|
|
6
|
|
|
12
|
|
|
Regulatory liabilities
|
|
|
541
|
|
|
488
|
|
|
Other
|
|
|
67
|
|
|
75
|
|
|
Total Deferred Credits
|
|
|
2,012
|
|
|
1,952
|
|
|
Commitments
and Contingencies (Note 10)
|
|
|
-
|
|
|
-
|
|
|
Total
|
|
$
|
7,626
|
|
$
|
7,366
|
|
See
Notes
to Consolidated Financial Statements.
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
|
For
the Years Ended December 31,
(Millions
of dollars)
|
|
2006
|
2005
|
2004
|
|
|||||
|
Operating
Revenues:
|
|
|
|
|
|
|
|
|||
|
Electric
|
|
$
|
1,886
|
$
|
1,912
|
|
$
|
1,692
|
|
|
|
Gas
|
|
|
505
|
509
|
|
|
397
|
|
||
|
Total Operating Revenues
|
|
|
2,391
|
2,421
|
|
|
2,089
|
|
||
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|||
|
Fuel used in electric generation
|
|
|
615
|
618
|
|
|
467
|
|
||
|
Purchased power
|
|
|
27
|
37
|
|
|
51
|
|
||
|
Gas purchased for resale
|
|
|
396
|
417
|
|
|
313
|
|
||
|
Other operation and maintenance
|
|
|
461
|
441
|
|
|
431
|
|
||
|
Depreciation and amortization
|
|
|
286
|
465
|
|
|
221
|
|
||
|
Other taxes
|
|
|
138
|
131
|
|
|
131
|
|
||
|
Total Operating Expenses
|
|
|
1,923
|
2,109
|
|
|
1,614
|
|
||
|
Operating
Income
|
|
|
468
|
312
|
|
|
475
|
|
||
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|||
|
Other revenues
|
|
|
61
|
163
|
|
|
103
|
|
||
|
Other expenses
|
|
|
(45
|
)
|
(140
|
)
|
|
(90
|
)
|
|
|
Gains on sale of investments and assets
|
3
|
-
|
1
|
|||||||
|
Allowance for equity funds used during construction
|
|
|
-
|
-
|
|
|
14
|
|
||
|
Interest charges, net of allowance for borrowed funds used during
construction of $8, $3 and $9
|
|
|
(140
|
)
|
(144
|
)
|
|
(139
|
)
|
|
|
Total Other Expense
|
|
|
(121
|
)
|
(121
|
)
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
|
|
|||
|
Income
Before Income Taxes (Benefit), Losses from Equity Method Investments,
Minority
|
|
|
|
|
|
|
|
|||
|
Interest, Cumulative Effect of Accounting Change and Preferred Stock
Dividends
|
|
|
347
|
191
|
|
|
364
|
|
||
|
Income
Tax Expense (Benefit)
|
|
|
88
|
(150
|
)
|
|
120
|
|
||
|
|
|
|
|
|
|
|
|
|||
|
Income
Before Losses from Equity Method Investments, Minority
Interest,
|
|
|
|
|
|
|
|
|||
|
Cumulative Effect of Accounting Change and Preferred Stock
Dividends
|
|
|
259
|
341
|
|
|
244
|
|
||
|
Losses
from Equity Method Investments
|
|
|
(22
|
)
|
(77
|
)
|
|
(2
|
)
|
|
|
Minority
Interest
|
|
|
7
|
6
|
|
|
10
|
|
||
|
Cumulative
Effect of Accounting Change, net of taxes
|
4
|
-
|
-
|
|||||||
|
|
|
|
|
|
|
|
|
|||
|
Net
Income
|
|
|
234
|
258
|
|
|
232
|
|
||
|
Preferred
Stock Cash Dividends
|
|
|
7
|
7
|
|
|
7
|
|
||
|
Earnings
Available for Common Shareholder
|
|
$
|
227
|
$
|
251
|
|
$
|
225
|
|
|
See
Notes
to Consolidated Financial Statements.
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For
the Years Ended December 31, (Millions of dollars)
|
|
2006
|
2005
|
2004
|
|
|||||
|
Cash
Flows From Operating Activities:
|
|
|
|
|
|
|
|
|||
|
Net
income
|
|
$
|
234
|
$
|
258
|
|
$
|
232
|
|
|
|
Adjustments
to reconcile net income to net cash provided from operating activities:
|
|
|
|
|
|
|
|
|||
|
Cumulative effect of accounting change, net of taxes
|
(4
|
)
|
-
|
-
|
||||||
|
Losses from equity method investments
|
|
|
22
|
77
|
|
|
2
|
|
||
|
Minority interest
|
|
|
7
|
6
|
|
|
10
|
|
||
|
Depreciation and amortization
|
|
|
286
|
465
|
|
|
221
|
|
||
|
Amortization of nuclear fuel
|
|
|
17
|
18
|
|
|
22
|
|
||
|
Gain on sale of assets
|
|
|
(3)
|
(1
|
)
|
|
(1
|
)
|
||
|
Allowance for equity funds used during construction
|
|
|
-
|
-
|
|
|
(14
|
)
|
||
|
Carrying cost recovery
|
|
|
(7
|
)
|
(11
|
)
|
|
-
|
|
|
|
Cash provided (used) by changes in certain assets and
liabilities:
|
|
|
|
|
|
|
|
|||
|
Receivables, net
|
|
|
49
|
(87
|
)
|
|
(19
|
)
|
||
|
Inventories
|
|
|
(146
|
)
|
(119
|
)
|
|
(44
|
)
|
|
|
Prepayments
|
|
|
(8)
|
18
|
|
|
(10
|
)
|
||
|
Pension asset
|
|
|
(13
|
)
|
(17
|
)
|
|
(14
|
)
|
|
|
Regulatory assets
|
|
|
(10
|
)
|
(30
|
)
|
|
(17
|
)
|
|
|
Deferred income taxes, net
|
|
|
14
|
19
|
|
|
44
|
|
||
|
Other regulatory liabilities
|
|
|
9
|
(165
|
)
|
|
42
|
|
||
|
Postretirement benefits
|
|
|
(3
|
)
|
6
|
|
|
7
|
|
|
|
Accounts payable
|
|
|
(16
|
)
|
6
|
|
|
(17
|
)
|
|
|
Taxes accrued
|
|
|
(28
|
)
|
(12
|
)
|
|
34
|
|
|
|
Interest accrued
|
|
|
(2
|
)
|
-
|
|
|
(4
|
)
|
|
|
Changes in fuel adjustment clauses
|
|
|
32
|
(32
|
)
|
|
8
|
|
||
|
Changes in other assets
|
|
|
19
|
(13
|
)
|
|
13
|
|
||
|
Changes in other liabilities
|
|
|
25
|
24
|
|
|
36
|
|
||
|
Net
Cash Provided From Operating Activities
|
|
|
474
|
410
|
|
|
531
|
|
||
|
Cash
Flows From Investing Activities:
|
|
|
|
|
|
|
|
|||
|
Utility property additions and construction expenditures
|
|
|
(409
|
)
|
(330
|
)
|
|
(434
|
)
|
|
|
Nonutility property additions
|
|
|
(3
|
)
|
(1
|
)
|
|
(5
|
)
|
|
|
Proceeds from sales of assets
|
|
|
3
|
2
|
|
|
2
|
|
||
|
Investments
|
|
|
(22
|
)
|
(18
|
)
|
|
(20
|
)
|
|
|
Net
Cash Used For Investing Activities
|
|
|
(431
|
)
|
(347
|
)
|
|
(457
|
)
|
|
|
Cash
Flows From Financing Activities:
|
|
|
|
|
|
|
|
|||
|
Proceeds from issuance of debt
|
|
|
132
|
121
|
|
|
136
|
|
||
|
Contribution from parent
|
|
|
9
|
95
|
|
|
38
|
|
||
|
Repayment of debt
|
|
|
(151
|
)
|
(264
|
)
|
|
(110
|
)
|
|
|
Redemption of preferred stock
|
|
|
-
|
(1
|
)
|
|
-
|
|
||
|
Dividends
|
|
|
(162
|
)
|
(158
|
)
|
|
(158
|
)
|
|
|
Distribution to parent
|
|
|
-
|
-
|
|
|
(29
|
)
|
||
|
Short-term borrowings - affiliate, net
|
|
|
75
|
(7
|
)
|
|
-
|
|
||
|
Short-term borrowings, net
|
|
|
59
|
150
|
|
|
13
|
|
||
|
Net
Cash Used For Financing Activities
|
|
|
(38
|
)
|
(64
|
)
|
|
(110
|
)
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
5
|
(1
|
)
|
|
(36
|
)
|
||
|
Cash
and Cash Equivalents, January 1
|
|
|
19
|
20
|
|
|
56
|
|
||
|
Cash
and Cash Equivalents, December 31
|
|
$
|
24
|
$
|
19
|
|
$
|
20
|
|
|
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
|||
|
Cash
paid for - Interest (net of capitalized interest of $8, $3 and
$9)
|
|
$
|
122
|
$
|
140
|
|
$
|
144
|
|
|
|
- Income taxes
|
|
|
93
|
26
|
|
|
22
|
|
||
|
Noncash
Investing and Financing Activities:
|
|
|
|
|
|
|
|
|||
|
Accrued construction expenditures
|
|
|
43
|
29
|
|
|
38
|
|
||
See
Notes
to Consolidated Financial Statements.
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED
STATEMENTS OF CHANGES IN COMMON
EQUITY
|
Accumulated
|
|||||||||||||||||||
|
Other
|
Other
|
Total
|
|||||||||||||||||
|
Common
Stock (a)
|
Paid
In
|
Retained
|
Comprehensive
|
Common
|
|||||||||||||||
|
Shares
|
Amount
|
Capital
|
Earnings
|
Income
(Loss)
|
Equity
|
||||||||||||||
|
(Millions)
|
|||||||||||||||||||
|
|
|
|
|
|
|||||||||||||||
|
Balance
at December 31, 2003
|
40
|
$
|
571
|
$
|
636
|
$
|
836
|
$
|
2,043
|
||||||||||
|
Capital Contributions From Parent
|
38
|
38
|
|||||||||||||||||
|
Earnings Available for Common Shareholder
|
225
|
225
|
|||||||||||||||||
|
Cash Dividends Declared
|
(142
|
)
|
(142
|
)
|
|||||||||||||||
|
Balance
at December 31, 2004
|
40
|
571
|
674
|
919
|
2,164
|
||||||||||||||
|
Capital Contributions From Parent
|
95
|
95
|
|||||||||||||||||
|
Earnings Available for Common Shareholder
|
251
|
251
|
|||||||||||||||||
|
Cash Dividends Declared
|
(148
|
)
|
(148
|
)
|
|||||||||||||||
|
Balance
at December 31, 2005
|
40
|
571
|
769
|
1,022
|
2,362
|
||||||||||||||
|
Capital Contributions From Parent
|
9
|
9
|
|||||||||||||||||
|
Earnings Available for Common Shareholder
|
227
|
227
|
|||||||||||||||||
|
Deferred Cost of Employee Benefit Plans,
|
|||||||||||||||||||
|
net of taxes $(4)
|
$
|
(7
|
)
|
(7
|
)
|
||||||||||||||
|
Cash Dividends Declared
|
(134
|
)
|
(134
|
)
|
|||||||||||||||
|
Balance
at December 31, 2006
|
40
|
$
|
571
|
$
|
778
|
$
|
1,115
|
$
|
(7
|
)
|
$
|
2,457
|
|||||||
(a)
$4.50
par value, authorized 50 million shares
The
Company adopted SFAS 158 at December 31, 2006 and recorded in accumulated other
comprehensive income gains, losses, prior service costs and credits that have
not yet been recognized through net periodic benefit cost, net of tax
effects.
See
Notes
to Consolidated Financial Statements.
1. SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization
and Principles of Consolidation
South
Carolina Electric & Gas Company (SCE&G, and together with its
consolidated affiliates, the Company), a public utility, is a South Carolina
corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation
(SCANA), a South Carolina corporation. The Company engages predominantly in
the
generation and sale of electricity to wholesale and retail customers in South
Carolina and in the purchase, sale and transportation of natural gas to retail
customers in South Carolina.
The
accompanying Consolidated Financial Statements reflect the accounts of
SCE&G, South Carolina Fuel Company, Inc. (Fuel Company) and South
Carolina Generating Company, Inc. (GENCO). Intercompany balances and
transactions between SCE&G, Fuel Company and GENCO have been eliminated in
consolidation.
Financial
Accounting Standards Board Interpretation No. 46 (Revised 2003) (FIN 46),
“Consolidation
of Variable Interest Entities,”
requires
an enterprise’s consolidated financial statements to include entities in which
the enterprise has a controlling financial interest. SCE&G has determined
that it has a controlling financial interest in GENCO and Fuel Company, and
accordingly, the accompanying condensed consolidated financial statements
include the accounts of SCE&G, GENCO and Fuel Company. The equity interests
in GENCO and Fuel Company are held solely by SCANA, the Company’s parent.
Accordingly, GENCO’s and Fuel Company’s equity and results of operations are
reflected as minority interest in the Company’s condensed consolidated financial
statements.
GENCO
owns a coal-fired electric generating station with a 615 megawatt net
generating capacity (summer rating). GENCO’s electricity is sold solely to
SCE&G under the terms of a power purchase agreement and related operating
agreement. Fuel Company acquires, owns and provides financing for SCE&G’s
nuclear fuel, fossil fuel and sulfur dioxide emission allowances. The effects
of
these transactions are eliminated in consolidation. Substantially all of GENCO’s
property (carrying value of approximately $261 million) serves as collateral
for
its long-term borrowings.
B. Basis
of Accounting
The
Company accounts for its regulated utility operations, assets and liabilities
in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) 71, “Accounting
for the Effects of Certain Types of Regulation.”
SFAS 71 requires cost-based rate-regulated utilities to recognize in their
financial statements certain revenues and expenses in different time periods
than do enterprises that are not rate-regulated. As a result, the Company has
recorded the regulatory assets and regulatory liabilities summarized as
follows.
|
|
|
December 31,
|
|
||||
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Regulatory
Assets:
|
|
|
|||||
|
Accumulated
deferred income taxes
|
|
$
|
169
|
|
$
|
170
|
|
|
Under-collections-electric
fuel and gas cost adjustment clauses
|
|
|
49
|
|
|
56
|
|
|
Purchased
power costs
|
|
|
9
|
|
|
17
|
|
|
Environmental
remediation costs
|
|
|
18
|
|
|
18
|
|
|
Asset
retirement obligations and related funding
|
|
|
254
|
|
|
240
|
|
|
Franchise
agreements
|
|
|
55
|
|
|
56
|
|
|
Regional
transmission organization costs
|
|
|
8
|
|
|
11
|
|
|
Deferred
employee benefit plan costs
|
128
|
-
|
|||||
|
Other
|
|
|
12
|
|
16
|
||
|
Total
Regulatory Assets
|
|
$
|
702
|
|
$
|
584
|
|
|
|
|
December 31,
|
|
||||
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Regulatory
Liabilities:
|
|||||||
|
Accumulated
deferred income taxes
|
$
|
34
|
$
|
36
|
|||
|
Other
asset removal costs
|
438
|
394
|
|||||
|
Storm
damage reserve
|
|
|
44
|
|
38
|
||
|
Planned
major maintenance
|
6
|
9
|
|||||
|
Other
|
|
|
19
|
|
11
|
||
|
Total
Regulatory Liabilities
|
|
$
|
541
|
|
$
|
488
|
|
Accumulated
deferred income tax liabilities arising from utility operations that have not
been included in customer rates are recorded as a regulatory asset. Accumulated
deferred income tax assets arising from deferred investment tax credits are
recorded as a regulatory liability.
Under-collections-electric
fuel and gas cost adjustment clauses, net, represent amounts under-collected
from customers pursuant to the fuel adjustment clause (electric customers)
or
gas cost adjustment clause (gas customers) as approved by the Public Service
Commission of South Carolina (SCPSC) during annual hearings. Included in these
amounts are regulatory assets or liabilities arising from the natural gas
hedging programs of the Company’s regulated operations. See Notes 1E and
1L.
Purchased
power costs represent costs necessitated by outages at two of SCE&G’s base
load generating plants in winter 2000-2001. The SCPSC approved recovery of
these
costs in base rates over a three year period beginning January 2005.
Environmental
remediation costs represent costs associated with the assessment and clean-up
of
manufactured gas plant (MGP) sites currently or formerly owned by SCE&G.
Costs incurred by SCE&G at such sites are being recovered through rates, of
which $17.9 million remain to be recovered.
Asset
retirement obligations (ARO) and related funding represents the regulatory
asset
associated with the legal obligation to decommission and dismantle V. C. Summer
Nuclear Station (Summer Station) and conditional AROs recorded as required
by
SFAS 143,
“Accounting for Asset Retirement Obligations,” and
Financial Accounting Standards Board Interpretation (FIN) 47, “Accounting
for Conditional Asset Retirement Obligations.”
Franchise
agreements represent costs associated with electric and gas franchise agreements
with the cities of Charleston and Columbia, South Carolina. SCE&G is
amortizing these amounts through cost of service rates and are expected to
be
amortized over approximately 20 years.
Regional
transmission organization costs represent costs incurred by SCE&G in the
United States Federal Energy Regulatory Commission (FERC)-mandated formation
of
GridSouth. The project was suspended in 2002. Effective January 2005, the
SCPSC approved the amortization of these amounts through cost of service rates
over approximately five years.
Deferred
employee benefit plan costs represent amounts of
pension and other postretirement benefit costs which were accrued as liabilities
under provisions of SFAS 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement
Plans,”
but
which are expected to be recovered through utility rates (see Note 3).
Other
asset removal costs represent net collections through depreciation rates of
estimated costs to be incurred for the removal of assets in the future.
The
storm
damage reserve represents an SCPSC-approved reserve account for SCE&G capped
at $50 million to be collected through rates. The accumulated reserve can
be applied to offset incremental storm damage costs in excess of $2.5 million
in
a calendar year. During the years ended December 31, 2006 and 2005, no
significant amounts were drawn from this reserve account.
Planned
major maintenance related to certain fossil and hydro-turbine equipment and
nuclear refueling outages is accrued in advance of the time the costs are
incurred, as approved through specific SCPSC orders. SCE&G is allowed to
collect $8.5 million annually over an eight-year period through electric rates
to offset turbine maintenance expenditures. Nuclear refueling charges are
accrued during each 18-month refueling outage cycle and are a component of
cost
of service and do not receive special rate consideration.
The
SCPSC
has reviewed and approved through specific orders most of the items shown as
regulatory assets. Other items represent costs which are not yet approved for
recovery by a state commission. In recording these costs as regulatory assets,
management believes the costs will be allowable under existing rate-making
concepts that are embodied in rate orders received by the Company. However,
ultimate recovery is subject to state commission approval. In the future, as
a
result of deregulation or other changes in the regulatory environment, the
Company may no longer meet the criteria for continued application of SFAS 71
and
could be required to write off its regulatory assets and liabilities. Such
an
event could have a material adverse effect on the Company’s results of
operations, liquidity or financial position in the period the write-off
would be recorded.
C. Utility
Plant and Major Maintenance
Utility
plant is stated substantially at original cost. The costs of additions, renewals
and betterments to utility plant, including direct labor, material and indirect
charges for engineering, supervision and an allowance for funds used during
construction, are added to utility plant accounts. The original cost of utility
property retired or otherwise disposed of is removed from utility plant accounts
and generally charged to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a
unit
of property or that do not increase the asset’s life or functionality are
charged to maintenance expense.
The
Company, operator of Summer Station, and the South Carolina Public Service
Authority (Santee Cooper) jointly own Summer Station in the proportions of
two-thirds and one-third, respectively. The parties share the operating costs
and energy output of the plant in these proportions. Each party, however,
provides its own financing. Plant-in-service related to the Company’s portion of
Summer Station was approximately $1.0 billion as of December 31, 2006 and
2005 (including amounts related to ARO). Accumulated depreciation associated
with the Company’s share of Summer Station was $496.8 million and
$478.7 million as of December 31, 2006 and 2005, respectively
(including amounts related to ARO). The Company’s share of the direct expenses
associated with operating Summer Station is included in other operation and
maintenance expenses and totaled $77.7 million, $76.3 million and
$74.5 million for the years ended December 31, 2006, 2005 and 2004,
respectively.
Planned
major maintenance related to certain fossil and hydro turbine equipment and
nuclear refueling outages is accrued in advance of the time the costs are
actually incurred in accordance with approval by the SCPSC for such accounting
treatment and rate recovery of expenses accrued thereunder. Other planned major
maintenance is expensed when incurred. Beginning in 2005, the Company is
collecting $8.5 million annually over an eight-year period through electric
rates to offset turbine maintenance expenditures. For the year ended December
31, 2006, the Company incurred $7.2 million for turbine maintenance. The
remaining $1.3 million is in a regulatory liability account on the balance
sheet. Nuclear refueling outages are scheduled 18 months apart, and the
Company begins accruing for each successive outage upon completion of the
preceding outage. SCE&G accrued $1.0 million per month from
July 2005 through December 2006 for its portion of the outage in
October 2006 and is accruing $1.1 million per month for its portion of the
outage scheduled for the spring of 2008. Total costs for the outage in 2006
were
$25.5 million, of which the Company was responsible for $17.0 million. As of
December 31, 2006 and 2005, the Company had accrued $0.2 million and
$5.7 million, respectively.
D. Allowance
for Funds Used During Construction (AFC)
AFC
is a
noncash item that reflects the period cost of capital devoted to plant under
construction. This accounting practice results in the inclusion of, as a
component of construction cost, the costs of debt and equity capital dedicated
to construction investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates for utility
services. The Company has calculated AFC using composite rates of 5.0%, 3.2%
and
6.7% for 2006, 2005 and 2004, respectively. These rates do not exceed the
maximum allowable rate as calculated under FERC Order No. 561. SCE&G
capitalizes interest on nuclear fuel in process at the actual interest amount
incurred.
E. Revenue
Recognition
The
Company records revenues during the accounting period in which it provides
services to customers and includes estimated amounts for electricity and natural
gas delivered but not yet billed. Unbilled revenues totaled $91.7 million
and $99.7 million as of December 31, 2006 and 2005,
respectively.
Fuel
costs
for electric generation are collected through the fuel cost component in retail
electric rates. This component is established by the SCPSC during annual fuel
cost hearings. Any difference between actual fuel costs and amounts contained
in
the fuel cost component is deferred and included when determining the fuel
cost
component during the next annual hearing. The Company had undercollected through
the electric fuel cost component $28.9 million and $44.1 million at
December 31, 2006 and 2005, respectively, which amounts are included in
other regulatory assets.
Customers
subject to the gas cost adjustment clause are billed based on a fixed cost
of
gas determined by the SCPSC during annual gas cost recovery hearings. Any
difference between actual gas costs and amounts contained in rates is deferred
and included when establishing gas costs during the next annual hearing. At
December 31, 2006 and 2005, the Company had undercollected $20.3 million
and $11.8 million, respectively, which amounts are also included in other
regulatory assets.
The
Company’s gas rate schedules for residential, small commercial and small
industrial customers include a weather normalization adjustment which minimizes
fluctuations in gas revenues due to abnormal weather conditions.
F. Depreciation
and Amortization
The
Company records provisions for depreciation and amortization using the
straight-line method based on the estimated service lives of the various classes
of property. The composite weighted average depreciation rates for utility
plant
assets were 3.15%, 3.16% and 2.97% for 2006, 2005 and 2004, respectively. These
rates reflect higher depreciation rates approved by the SCPSC in connection
with
electric and gas rate cases effective January 2005 and November 2005,
respectively.
The
Company records nuclear fuel amortization using the units-of-production method.
Nuclear fuel amortization is included in “Fuel used in electric generation” and
recovered through the fuel cost component of retail electric rates. Provisions
for amortization of nuclear fuel include amounts necessary to satisfy
obligations to the Department of Energy (DOE) under a contract for disposal
of
spent nuclear fuel.
G. Nuclear
Decommissioning
The
Company’s two-thirds share of estimated site-specific nuclear decommissioning
costs for Summer Station, including the cost of decommissioning plant components
both subject to and not subject to radioactive contamination, totals
$451.0 million, stated in 2006 dollars, based on a decommissioning study
completed in 2006. Santee Cooper is responsible for decommissioning costs
related to its one-third ownership interest in Summer Station. The cost estimate
assumes that the site would be maintained over a period of 60 years in such
a manner as to allow for subsequent decontamination that would permit release
for unrestricted use.
Under
the
Company’s method of funding decommissioning costs, amounts collected through
rates ($3.2 million pre-tax in each of 2006, 2005 and 2004) are invested in
insurance policies on the lives of certain Company and affiliate personnel.
The
Company transfers to an external trust fund the amounts collected through
electric rates, insurance proceeds and interest on proceeds, less expenses.
The
trusteed asset balance reflects the net cash surrender value of the insurance
policies and cash held by the trust. Management intends for the fund, including
earnings thereon, to provide for all eventual decommissioning expenditures
on an
after-tax basis.
H. Income
and Other Taxes
The
Company is included in the consolidated federal income tax return of SCANA.
Under a joint consolidated income tax allocation agreement, each SCANA
subsidiary’s current and deferred tax expense is computed on a stand-alone
basis. Deferred tax assets and liabilities are recorded for the tax effects
of
all significant temporary differences between the book basis and tax basis
of
assets and liabilities at currently enacted tax rates. Deferred tax assets
and
liabilities are adjusted for changes in such tax rates through charges or
credits to regulatory assets or liabilities if they are expected to be recovered
from, or passed through to, customers; otherwise, they are charged or credited
to income tax expense. Also under provisions of the income tax allocation
agreement, certain tax benefits of the parent holding company are distributed
in
cash to tax paying affiliates, including the Company, in the form of capital
contributions. The Company received capital contributions under such provisions
of $10.1 million in 2006 and $5.4 million in 2005.
The
Company records excise taxes billed and collected, as well as local franchise
and similar taxes, as liabilities until they are remitted to the respective
taxing authority. Accordingly, no such taxes are included in revenues or
expenses in the statements of income.
I. Debt
Premium, Discount and Expense, Unamortized Loss on Reacquired
Debt
The
Company records long-term debt premium and discount in long-term debt and
amortizes them as components of interest charges over the terms of the
respective debt issues. Other issuance expense and gains or losses on reacquired
debt that is refinanced are recorded in other deferred debits or credits and
amortized over the term of the replacement debt.
J. Environmental
The
Company maintains an environmental assessment program to identify and evaluate
current and former operations sites that could require environmental cleanup.
As
site assessments are initiated, estimates are made of the amount of
expenditures, if any, deemed necessary to investigate and clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates.
K. Cash
and Cash Equivalents
The
Company considers temporary cash investments having original maturities of
three
months or less at time of purchase to be cash equivalents. These cash
equivalents are generally in the form of commercial paper, certificates of
deposit, repurchase agreements, treasury bills and notes.
L. Commodity
Derivatives
The
Company hedges gas purchasing activities using over-the-counter options and
swaps and New York Mercantile Exchange (NYMEX) futures and options. SCE&G’s
tariffs include a purchased gas adjustment (PGA) clause that provides for the
recovery of actual gas costs incurred. The SCPSC has ruled that the results
of
these hedging activities are to be included in the PGA. As such, costs of
related derivatives utilized to hedge gas purchasing activities are recoverable
through the weighted average cost of gas calculation. The offset to the change
in fair value of these derivatives is recorded as a regulatory asset or
liability.
M. New
Accounting Matters
SFAS
123(R) requires compensation costs related to share-based payment transactions
to be recognized in the financial statements. With limited exceptions,
compensation cost is measured based on the grant-date fair value of the
instruments issued and is recognized over the period that an employee provides
service in exchange for the award. SFAS 123(R) replaced SFAS 123, “Accounting
for Stock-Based Compensation,” and
superseded Accounting Principles Board (APB) Opinion 25, “Accounting
for Stock Issued to Employees.”
The
Company adopted SFAS 123(R) in the first quarter of 2006. The impact on the
Company’s results of operations is discussed at Note 3.
The
Company adopted SFAS 154, “Accounting
Changes and Error Corrections,” in
the
first quarter of 2006. SFAS 154 requires retrospective application to financial
statements of prior periods for every voluntary change in accounting principle
unless such retrospective application is impracticable. SFAS 154 replaces APB
20, “Accounting
Changes,”
and SFAS
3, “Reporting
Accounting Changes in Interim Financial Statements.” The
adoption of SFAS 154 had no impact on the Company’s results of operations, cash
flows or financial position.
SFAS
157,
“Fair
Value Measurements,”
was
issued in September 2006. SFAS 157 establishes a framework for measuring
fair value to increase the consistency and comparability in fair value
measurements. The Company will adopt SFAS 157 in the first quarter of
2008, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows or financial
position.
In
September 2006, SFAS 158, “Employers'
Accounting for Defined Benefit Pension and Other Postretirement
Plans,”
amended SFAS 87 and SFAS 106 to require recognition of the overfunded or
underfunded status of pension and other postretirement benefit plans on the
balance sheet. Under SFAS 158, gains and losses, prior service costs and
credits, and any remaining transition amounts under SFAS 87 and SFAS 106 that
have not yet been recognized through net periodic benefit cost are to be
recognized in accumulated other comprehensive income, net of tax effects, until
they are amortized as a component of net periodic cost. The Company adopted
SFAS
158 as of December 31, 2006. Because a significant amount of the Company’s
pension and other postretirement costs recorded under SFAS 87 and SFAS 106
are
attributable to employees in its regulated operations, the adoption of SFAS
158
primarily resulted in the recording of additional regulatory assets. The impact
of adoption on the Company’s financial position is detailed at Note 3. The
adoption did not have an impact on the Company’s results of operations or cash
flows.
SFAS
159,
“The
Fair Value Option for Financial Assets and Financial
Liabilities,”
was
issued in February 2007. SFAS 159 allows entities to measure at fair value
many
financial instruments and certain other assets and liabilities that are not
otherwise required to be measured at fair value. SFAS 159 is effective for
fiscal years beginning after November 15, 2007. The Company has not determined
what impact, if any, that adoption will have on the Company’s results of
operations, cash flows or financial position.
FIN
48,
“Accounting
for Uncertainty in Income Taxes,” was
issued in June 2006. FIN 48 clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements in accordance with SFAS
109,“Accounting
for Income Taxes.” FIN
48
prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of tax positions taken or expected to
be
taken in a tax return. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure and transition. The Company will adopt FIN 48 in the first quarter
of
2007, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows and financial
position.
FASB
Staff Position (FSP) AUG AIR-1 “Accounting
for Planned Major Maintenance Activities,”
was
issued in September 2006 and amends APB 28, “Interim
Financial Reporting,”
to
prohibit the use of the accrue-in-advance method of accounting for planned
major
maintenance in annual and interim financial reporting periods. As
disclosed in Note 1A, the Company has received specific SCPSC orders providing
for use of accrue-in-advance accounting for certain planned major maintenance
activities. Accordingly, the Company will follow SFAS 71 when accounting for
these activities. The Company will adopt FSP AUG AIR-1 in the first quarter
of
2007, and does not expect that the initial adoption will have a material impact
on the Company’s results of operations, cash flows or financial position.
The
United States Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin 108 (SAB 108) in September 2006. SAB 108 provides guidance on the
consideration of the effects of prior year misstatements in quantifying and
assessing the materiality of current year misstatements. SAB 108 also
provides transition guidance for correcting errors existing from prior
years. The Company adopted SAB 108 in December 2006. The adoption had no
impact on the Company’s results of operations, cash flows or financial
position.
N. Affiliated
Transactions
The
Company has entered into agreements with certain affiliates to purchase gas
for
resale to its distribution customers and for generating electric energy. The
Company purchased natural gas for resale and electric generation from South
Carolina Pipeline Corporation (SCPC) and had approximately $72.1 million payable
to SCPC for such gas purchases at December 31, 2005. Effective November 1,
2006,
SCG Pipeline, Inc. (SCG Pipeline) merged into SCPC and the merged company
changed its name to Carolina Gas Transmission Corporation (CGTC). The Company
had approximately $1.9 million payable to CGTC for transportation services
at
December 31, 2006.
In
2006,
the Company purchased LNG facilities and LNG inventory from SCPC for
approximately $17.1 million and $17.2 million, respectively. The Company also
purchased underground gas storage inventory from SCPC for approximately $40.3
million. In 2005, the Company purchased approximately 338 miles of gas
distribution pipeline from SCPC for approximately $21.7 million.
Total
interest income, based on market interest rates, associated with the Company’s
advances to affiliated companies in 2006 and 2005 was not significant.
The
Company
purchases natural gas and related pipeline capacity from SCANA Energy
Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating
Station and to serve its retail gas customers. Such purchases totaled
approximately $114.5 million and $128.5 million for the years ended
December 31, 2006 and 2005, respectively. SCE&G had approximately $14.0
million and $8.0 million payable to SEMI for such purposes as of December
31, 02006 and 2005, respectively.
The
Company holds equity-method investments in two partnerships involved in
converting coal to synthetic fuel. The Company had recorded as receivables
from
these affiliated companies of approximately $31.8 million and
$24.6 million at December 31, 2006 and 2005, respectively. The Company
had recorded as payables to these affiliated companies totaling approximately
$26.6 million and $25.3 million at December 31, 2006 and 2005,
respectively. The Company purchased approximately $291.1 million,
$248.1 million and $190.6 million of synthetic fuel from these
affiliated companies in 2006, 2005 and 2004, respectively. The Company made
cash
investments in these affiliated companies of $18.4 million in 2006, $17.7
million in 2005 and $18.7 million in 2004.
O. Use
of Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amount of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
2. RATE
AND OTHER REGULATORY MATTERS
Electric
In
a
January 2005 order, the SCPSC granted SCE&G a composite increase in
retail electric rates of 2.89%, designed to produce additional annual revenues
of $41.4 million based on a test year calculation. The SCPSC lowered
SCE&G’s allowed return on common equity from 12.45% to an amount not to
exceed 11.4%, with rates set at 10.7%. The new rates became effective in
January 2005. As part of its order, the SCPSC approved SCE&G’s recovery
of construction and operating costs for SCE&G’s new Jasper County Electric
Generating Station, recovery of costs of mandatory environmental upgrades
primarily related to Federal Clean Air Act regulations and, beginning in January
2005, the application of current and anticipated net synthetic fuel tax credits
to offset the cost of constructing the back-up dam at Lake Murray. Under the
accounting methodology approved by the SCPSC, construction costs related to
the
Lake Murray back-up dam project were recorded in a special dam remediation
account outside of rate base, and depreciation is being recognized against
the
balance in this account on an accelerated basis, subject to the availability
of
the synthetic fuel tax credits.
In
the
January 2005 order, the SCPSC also approved recovery over a five-year period
of
SCE&G’s approximately $14 million of costs incurred in the formation of the
GridSouth Regional Transmission Organization and recovery through base rates
over three years of $25.6 million of purchased power costs that were
previously deferred. As a part of its order, the SCPSC extended through 2010
its
approval of the accelerated capital recovery plan for SCE&G’s Cope
Generating Station. Under the plan, in the event that SCE&G would otherwise
earn in excess of its maximum allowed return on common equity, SCE&G may
increase depreciation of its Cope Generating Station up to $36 million
annually without additional approval of the SCPSC. Any unused portion of the
$36
million in any given year may be carried forward for possible use in the
immediately following year. No such additional depreciation was recognized
in
2006, 2005 or 2004.
SCE&G’s
rates are established using a cost of fuel component approved by the SCPSC
which
may be modified periodically to reflect changes in the price of fuel purchased
by SCE&G. SCE&G’s cost of fuel component in effect during 2006 and 2005
was as follows:
|
Rate Per KWh
|
Effective Date
|
|
$.01764
|
January-April
2005
|
|
$.02256
|
May
2005-April 2006
|
|
$.02516
|
May-December
2006
|
In
connection with the May 2006 fuel component increase, SCE&G agreed to spread
the recovery of previously undercollected fuel costs of $38.5 million over
a
two-year period.
Gas
In
October 2005, the SCPSC granted SCE&G an overall increase of $22.9 million,
or 5.69%, in retail gas base rates. The new rates are based on an allowed return
on common equity of 10.25%, and became effective with the first billing cycle
in
November 2005.
In
June
2006, SCE&G reported to the SCPSC that its return on common equity for the
twelve months ended March 31, 2006 was more than 0.5% below the allowed return,
and as provided under South Carolina’s Natural Gas Rate Stabilization Act,
SCE&G requested an annualized increase in certain natural gas base rates. In
September 2006, the SCPSC approved an annual increase of $17.4 million. The
rate
adjustment was effective with the first billing cycle in November
2006.
SCE&G's
rates are established using a cost of gas component approved by the SCPSC which
may be modified periodically to reflect changes in the price of natural gas
purchased by SCE&G. SCE&G's cost of gas components by class were as
follows (rate per therm):
|
Effective
Date
|
|
Residential
|
|
Small/Medium
|
|
Large
|
|
|||
|
January-October
2005
|
|
$.903
|
|
$.903
|
|
$.903
|
|
|||
|
November
2005
|
|
|
1.297
|
|
|
1.222
|
|
|
1.198
|
|
|
December
2005
|
|
|
1.362
|
|
|
1.286
|
|
|
1.263
|
|
|
January
2006
|
|
|
1.297
|
|
|
1.222
|
|
|
1.198
|
|
|
February-October
2006
|
|
|
1.227
|
|
|
1.152
|
|
|
1.128
|
|
|
November
2006
|
1.115
|
1.004
|
.963
|
|||||||
|
December
2006
|
1.240
|
1.130
|
1.090
|
|||||||
In
October 2006, the SCPSC approved a reduction in the cost of gas component of
SCE&G’s retail natural gas rates, effective with the first billing cycle of
November 2006. The SCPSC also authorized SCE&G to adjust its cost of gas on
a monthly, rather than an annual, basis beginning in December 2006.
Prior
to
November 2005, the SCPSC allowed SCE&G to recover through a billing
surcharge to its gas customers the costs of environmental cleanup at the sites
of former MGPs. Effective with the first billing cycle of November 2005, the
billing surcharge was eliminated. In its place, SCE&G defers certain MGP
environmental costs in regulatory asset accounts and collects and amortizes
these costs through base rates.
3. EMPLOYEE
BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension
and Other Postretirement Benefit Plans
The
Company participates in SCANA’s noncontributory defined benefit pension plan,
which covers substantially all permanent employees. The Company’s policy has
been to fund the plan to the extent permitted by applicable federal income
tax
regulations as determined by an independent actuary.
Effective
July 1, 2000 SCANA's pension plan, which provided a final average pay
formula, was amended to provide a cash balance formula for employees hired
before January 1, 2000 who elected that option and for all employees hired
on or
after January 1, 2000. For employees who elected to remain under the final
average pay formula, benefits are based on years of credited service and the
employee's average annual base earnings received during the last three years
of
employment. For employees under the cash balance formula, benefits accumulate
as
a result of compensation credits and interest credits.
In
addition to pension benefits, the Company participates in SCANA’s unfunded
postretirement health care and life insurance programs which provide benefits
to
active and retired employees. Retirees share in a portion of their medical
care
cost. The Company provides life insurance benefits to retirees at no charge.
The
costs of postretirement benefits other than pensions are accrued during the
years the employees render the services necessary to be eligible for these
benefits.
The
Company
adopted the balance sheet recognition provisions of SFAS 158 at December 31,
2006. The incremental effect of applying SFAS 158 on individual line items
in
the balance sheet was as follows:
|
Before
|
After
|
|||||||||
|
Application
of
|
Application
of
|
|||||||||
|
December
31, 2006
|
SFAS
158
|
Adjustments
|
SFAS
158
|
|||||||
|
Millions
of dollars
|
||||||||||
|
Deferred
debits - pension asset, net
|
$
|
316.7
|
$
|
(117.2
|
)
|
$
|
199.5
|
|||
|
Deferred
debits - regulatory assets
|
575.2
|
127.1
|
702.3
|
|||||||
|
Due
from affiliates - pension and postretirement
|
26.6
|
14.9
|
41.5
|
|||||||
|
Deferred
debits - other
|
124.8
|
2.3
|
127.1
|
|||||||
|
Total
deferred debits
|
1,070.1
|
27.1
|
1,097.2
|
|||||||
|
Total
assets
|
7,599.2
|
27.1
|
7,626.3
|
|||||||
|
Common
equity
|
2,464.1
|
(6.7
|
)
|
2,457.4
|
||||||
|
Total
shareholders’ investment
|
2,570.4
|
(6.7
|
)
|
2,563.7
|
||||||
|
Total
capitalization
|
4,585.6
|
(6.7
|
)
|
4,578.9
|
||||||
|
Current
liabilities - other
|
49.5
|
12.9
|
62.4
|
|||||||
|
Total
current liabilities
|
935.8
|
12.9
|
948.7
|
|||||||
|
Deferred
credits - deferred income taxes, net
|
811.7
|
(4.5
|
)
|
807.2
|
||||||
|
Deferred
credits - postretirement benefits
|
158.2
|
35.8
|
194.0
|
|||||||
|
Due
to affiliates - pension and postretirement
|
9.0
|
(3.5
|
)
|
5.5
|
||||||
|
Deferred
credits - other
|
74.2
|
(6.9
|
)
|
67.3
|
||||||
|
Total
deferred credits
|
1,992.0
|
20.9
|
2,012.9
|
|||||||
|
Total
capitalization and liabilities
|
7,599.2
|
27.1
|
7,626.3
|
|||||||
Funded
Status
The
funded status at the end of the year and the related amounts recognized on
the
balance sheets follow:
|
Pension
Benefits
|
Other
Postretirement Benefits
|
||||||||||||
|
December
31,
|
December
31,
|
||||||||||||
|
2006
|
2005
|
2006
|
2005
|
||||||||||
|
Millions
of Dollars
|
|||||||||||||
|
Fair
value of plan assets
|
$
|
912.5
|
$
|
854.3
|
-
|
-
|
|||||||
|
Benefit
obligations
|
713.0
|
711.4
|
$
|
206.9
|
$
|
202.1
|
|||||||
|
Funded
status
|
199.5
|
142.9
|
(206.9
|
)
|
(202.1
|
)
|
|||||||
|
Unrecognized
net actuarial loss
|
n/a
|
88.4
|
n/a
|
44.4
|
|||||||||
|
Unrecognized
prior service cost
|
n/a
|
71.3
|
n/a
|
5.2
|
|||||||||
|
Unrecognized
transition obligation
|
n/a
|
0.6
|
n/a
|
4.3
|
|||||||||
|
Amount
recognized, end of year
|
$
|
199.5
|
$
|
303.2
|
$
|
(206.9
|
)
|
$
|
(148.2
|
)
|
|||
Amounts
recognized on the balance sheets consist of:
|
Noncurrent
asset
|
$
|
199.5
|
n/a
|
-
|
n/a
|
||||||||
|
Current
liability
|
-
|
n/a
|
$
|
(12.9
|
)
|
n/a
|
|||||||
|
Noncurrent
liability
|
-
|
n/a
|
(194.0
|
)
|
n/a
|
||||||||
|
Prepaid
benefit cost
|
n/a
|
$
|
303.2
|
n/a
|
n/a
|
||||||||
|
Accrued
benefit cost
|
n/a
|
-
|
n/a
|
$
|
(148.2
|
)
|
Deferred
amounts recognized in accumulated other comprehensive income, which is a
component of common equity, as of December 31, 2006, including the adjustment
above to reflect the adoption of SFAS 158, were as follows:
|
December
31, 2006
|
Pension
Benefits
|
Other
Postretirement
Benefits
|
Total
|
|||||||
|
Millions
of dollars
|
||||||||||
|
Transition
Obligation
|
-
|
$
|
0.1
|
$
|
0.1
|
|||||
|
Prior
Service Costs
|
-
|
0.2
|
0.2
|
|||||||
|
Actuarial
Losses
|
$
|
5.9
|
0.5
|
6.4
|
||||||
|
Total
|
$
|
5.9
|
$
|
0.8
|
$
|
6.7
|
||||
The
estimated transition obligation, prior service costs and actuarial losses for
the defined benefit plans that will be amortized from accumulated other
comprehensive income into net periodic benefit costs during 2007 are less than
$100,000 in aggregate.
Changes
in Benefit Obligations
The
measurement date used to determine pension and other postretirement benefit
obligations is December 31. Data related to the changes in the projected
benefit obligation for retirement benefits and the accumulated benefit
obligation for other postretirement benefits are presented below.
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||
|
|
|
2006
|
2005
|
2006
|
2005
|
|
|||||||
|
|
|
Millions
of dollars
|
|
||||||||||
|
Benefit
obligation, January 1
|
|
$
|
711.5
|
|
$
|
669.5
|
|
$
|
202.1
|
|
$
|
197.5
|
|
|
Service
cost
|
|
|
14.0
|
|
|
12.2
|
|
|
4.6
|
|
|
3.5
|
|
|
Interest
cost
|
|
|
39.8
|
|
|
38.3
|
|
|
11.5
|
|
|
10.7
|
|
|
Plan
participants’ contributions
|
|
|
-
|
|
|
-
|
|
|
2.1
|
|
|
2.3
|
|
|
Plan
amendments
|
|
|
0.6
|
|
|
-
|
|
|
4.0
|
|
(0.3
|
)
|
|
|
Actuarial
(gain) loss
|
|
|
(14.4
|
)
|
|
27.1
|
|
|
(5.5
|
)
|
|
1.5
|
|
|
Benefits
paid
|
|
|
(38.5
|
)
|
|
(35.6
|
)
|
|
(11.9
|
)
|
|
(13.1
|
)
|
|
Benefit
obligation, December 31
|
|
$
|
713.0
|
|
$
|
711.5
|
|
$
|
206.9
|
|
$
|
202.1
|
|
The
accumulated benefit obligation for retirement benefits at the end of 2006 and
2005 was $666.6 million and $664.4 million, respectively. These
accumulated retirement benefit obligations differ from the projected retirement
benefit obligations above in that they reflect no assumptions about future
compensation levels.
Significant
assumptions used to determine the above benefit obligations are as
follows:
|
|
|
2006
|
2005
|
|
|||
|
Annual
discount rate used to determine benefit obligations
|
|
|
5.85
|
%
|
|
5.60
|
%
|
|
Assumed
annual rate of future salary increases for projected benefit
obligation
|
|
|
4.00
|
%
|
|
4.00
|
%
|
A
9.5%
annual rate of increase in the per capita cost of covered health care benefits
was assumed for 2006. The rate was assumed to decrease gradually to 5.0% for
2013 and to remain at that level thereafter. The effects of a
one-percentage-point increase or decrease in the annual rate on accumulated
other postretirement benefit obligation for health care benefits are as
follows:
|
|
|
1%
Increase
|
1%
Decrease
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Effect
on postretirement benefit obligation
|
|
$
|
3.1
|
|
$
|
(2.7
|
)
|
Changes
in Plan Assets
|
|
|
Retirement
Benefits
|
|
||||
|
|
|
2006
|
2005
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Fair
value of plan assets, January 1
|
|
$
|
854.3
|
$
|
846.7
|
|
|
|
Actual
return on plan assets
|
|
|
96.7
|
|
43.2
|
|
|
|
Benefits
paid
|
|
|
(38.5
|
)
|
|
(35.6
|
)
|
|
Fair
value of plan assets, December 31
|
|
$
|
912.5
|
$
|
854.3
|
|
|
The
Company determines the fair value of substantially all of its pension assets
utilizing market quotes rather than utilizing any calculated values, “market
related” values or other modeling techniques. At the end of 2006 and 2005, the
fair value of plan assets for the pension plan exceeded both the projected
benefit obligation and the accumulated benefit obligation discussed above.
In
connection with the joint ownership of Summer Station, as of December 31,
2006 and 2005, the Company recorded within deferred credits a $3.6 million
and $10.2 million obligation, respectively, to Santee Cooper, representing
an
estimate of the net pension asset attributable to the Company’s contributions to
the pension plan that were recovered through billings to Santee Cooper for
its
one-third portion of shared costs. As of December 31, 2006 and 2005, the
Company also recorded within deferred debits a $9.9 million and
$7.1 million receivable, respectively, from Santee Cooper, representing an
estimate of its portion of the unfunded net postretirement benefit
obligation.
Expected
Cash Flows
The
total
benefits expected to be paid from the pension plan or from the Company’s assets
for the other postretirement benefits plan, respectively, are as
follows:
|
|
Other
Postretirement Benefits*
|
|
||||||||
|
Expected
Benefit Payments
|
Pension
Benefits
|
Excluding
Medicare Subsidy
|
Including
Medicare Subsidy
|
|
||||||
|
|
|
Millions
of dollars
|
|
|||||||
|
2007
|
|
$
|
39.7
|
|
$
|
10.0
|
|
$
|
9.7
|
|
|
2008
|
|
|
40.1
|
|
|
10.3
|
|
|
10.0
|
|
|
2009
|
|
|
40.5
|
|
|
10.3
|
|
|
10.0
|
|
|
2010
|
|
|
40.9
|
|
|
10.6
|
|
|
10.3
|
|
|
2011
|
|
|
41.3
|
|
|
10.8
|
|
|
10.4
|
|
|
2012-2016
|
|
|
212.8
|
|
|
57.4
|
|
|
56.0
|
|
*
Net of
participant contributions
Net
Periodic Cost
As
allowed by SFAS 87 and SFAS 106, as amended, the Company records net
periodic benefit cost (income) utilizing beginning of the year assumptions.
Disclosures required for these plans under SFAS 132, “Employer’s
Disclosures about Pensions and Other Postretirement Benefits,”
as
amended, are set forth in the following tables.
Components
of Net Periodic Benefit Cost (Income)
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||||||||
|
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|
|||||||||||
|
|
|
Millions
of dollars
|
|
||||||||||||||||
|
Service
cost
|
|
$
|
14.0
|
$
|
12.2
|
|
$
|
11.1
|
|
$
|
4.6
|
$
|
3.5
|
|
$
|
3.3
|
|
||
|
Interest
cost
|
|
|
39.8
|
38.3
|
|
|
37.4
|
|
|
11.5
|
10.7
|
|
|
11.4
|
|
||||
|
Expected
return on assets
|
|
|
(75.2
|
)
|
(76.3
|
)
|
|
(71.0
|
)
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|||
|
Prior
service cost amortization
|
|
|
6.8
|
6.9
|
|
|
6.6
|
|
|
1.1
|
0.8
|
|
|
1.4
|
|
||||
|
Amortization
of actuarial loss
|
|
|
0.5
|
-
|
|
|
-
|
|
|
1.7
|
1.2
|
|
|
1.9
|
|
||||
|
Transition
amount amortization
|
|
|
0.6
|
0.8
|
|
|
0.8
|
|
|
0.8
|
0.8
|
|
|
0.8
|
|
||||
|
Amount
attributable to Company affiliates
|
|
|
(2.5
|
)
|
(1.9
|
)
|
|
(1.7
|
)
|
|
(5.4
|
)
|
(4.8
|
)
|
|
(5.5
|
)
|
||
|
Net
periodic benefit (income) cost
|
|
$
|
16.0
|
$
|
(20.0
|
)
|
$
|
(16.8
|
)
|
$
|
14.3
|
$
|
12.2
|
|
$
|
13.3
|
|
||
Significant
Assumptions Used in Determining Net Periodic Benefit Cost
(Income)
|
|
|
Retirement
Benefits
|
Other
Postretirement Benefits
|
|
|||||||||||||||
|
|
|
2006
|
2005
|
2004
|
2006
|
2005
|
2004
|
|
|||||||||||
|
Discount
rate
|
|
|
5.60
|
%
|
5.75
|
%
|
|
6.00
|
%
|
|
5.60
|
%
|
5.75
|
%
|
|
6.00
|
%
|
||
|
Expected
return on plan assets
|
|
|
9.00
|
%
|
9.25
|
%
|
|
9.25
|
%
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|||
|
Rate
of compensation increase
|
|
|
4.00
|
%
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
4.00
|
%
|
|
4.00
|
%
|
||
|
Health
care cost trend rate
|
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|
9.00
|
%
|
9.00
|
%
|
|
9.50
|
%
|
|||
|
Ultimate
health care cost trend rate
|
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|
5.00
|
%
|
5.00
|
%
|
|
5.00
|
%
|
|||
|
Year
achieved
|
|
|
n/a
|
n/a
|
|
|
n/a
|
|
|
2012
|
2011
|
|
|
2011
|
|
||||
The
effect of a one-percentage-point increase or decrease in the assumed health
care
cost trend rate on total service and interest cost is less than
$250,000.
Pension
Plan Contributions
The
pension trust is adequately funded. No contributions have been required since
1997, and the Company does not anticipate making contributions to the pension
plan until after 2010.
Pension
Plan Asset Allocations
The
Company’s pension plan asset allocation at December 31, 2006 and 2005 and
the target allocations for 2007 are as follows:
|
|
|
Target
Allocation
|
Percentage of Plan Assets
At
December 31,
|
|
||||||
|
Asset
Category
|
|
2007
|
2006
|
2005
|
|
|||||
|
Equity
Securities
|
|
|
70
|
%
|
72
|
%
|
|
72
|
%
|
|
|
Debt
Securities
|
|
|
30
|
%
|
28
|
%
|
|
28
|
%
|
|
The
assets of the pension plan are invested in accordance with the objectives of
(1) fully funding the actuarial accrued liability for the pension plan
(Plan), (2) maximizing return within reasonable and prudent levels of risk
in order to minimize contributions, and (3) maintaining sufficient
liquidity to meet benefit payment obligations on a timely basis. The pension
plan operates with several risk and control procedures including ongoing reviews
of liabilities, investment objectives, investment managers and performance
expectations. Transactions involving certain types of investments are
prohibited. Equity securities held by the pension plan during the above periods
did not include SCANA common stock.
In
developing the expected long-term rate of return assumptions, management
evaluates the pension plan’s historical cumulative actual returns over several
periods, which have all been in excess of related broad indices. The expected
long-term rate of return of 9.0% assumes an asset allocation of 70% with equity
managers and 30% with fixed income managers. Management regularly reviews such
allocations and periodically rebalances the portfolio when considered
appropriate. For 2007 the expected rate of return will be 9.0%.
Share-Based
Compensation
The
Company participates in the SCANA Long-Term Equity Compensation Plan provides
for grants of incentive nonqualified stock options, stock appreciation rights,
restricted stock, performance shares and performance units to certain key
employees and non-employee directors. The plan currently authorizes the issuance
of up to five million shares of SCANA’s common stock, no more than one million
of which may be granted in the form of restricted stock.
SFAS
123
(revised 2004), “Share-Based
Payment”
(SFAS
123(R)), requires compensation costs related to share-based payment transactions
to be recognized in the financial statements. With limited exceptions,
compensation cost is measured based on the grant-date fair value of the
instruments issued and is recognized over the period that an employee provides
service in exchange for the award. The cumulative effect of the adoption of
SFAS
123(R) on January 1, 2006 resulted in a $4 million (net of tax) gain in the
first quarter of 2006 based on a reduction of prior compensation accruals for
performance awards (discussed below) granted in 2004 and 2005.
Liability
Awards
Through
2006, certain executives were granted a target number of performance shares
on
an annual basis that vest over a three-year period. Each performance share
has a
value that is equal to, and changes with, the value of a share of SCANA common
stock, and dividend equivalents are accrued on, and reinvested in, the
performance shares. Payout of performance share awards is determined by SCANA's
performance against pre-determined measures of total shareholder return (TSR)
as
compared to a peer group of utilities (weighted 60%) and growth in earnings
per
share (weighted 40%) over the three year plan cycle. TSR is calculated by
dividing stock price change over the three-year period, plus cash dividends,
by
the stock price as of the beginning of the period. Payouts vary according to
SCANA's ranking against the peer group and relative earnings per share
projection achievement. Awards are designated as target shares of SCANA common
stock and may be paid in stock or cash or a combination of stock and cash at
SCANA's discretion.
Under
SFAS 123(R) compensation cost of these liability awards is recognized over
the
three-year performance period based on the estimated fair value of the award,
which is periodically updated based on expected ultimate cash payout, and is
reduced by estimated forfeitures. Cash-settled liabilities totaling $1.2 million
were paid during the twelve months ended December 31, 2006. No such payments
were made in 2005.
Fair
value adjustments for performance awards resulted in a reduction to compensation
expense recognized in the condensed statements of income, exclusive of the
cumulative effect adjustment discussed previously, totaling $(4.8) million
for
the year ended December 31, 2006, and increases to compensation expense totaling
$2.3 million and $8.4 million for the years ended December 31, 2005 and 2004,
respectively. Fair value adjustments resulted in a net credit to capitalized
compensation cost of approximately $(0.7) million during the year ended December
31, 2006, compared to capitalized costs of approximately $0.3 million in 2005
and $1.8 million in 2004.
Equity
Awards
A
summary
of activity related to nonqualified stock options since December 31, 2003
follows:
|
|
Number
of
Options
|
Weighted
Average
Exercise Price
|
|||||
|
Outstanding-December
31, 2003
|
1,493,685
|
$
|
27.39
|
||||
|
Exercised
|
(751,997
|
)
|
$
|
26.28
|
|||
|
Forfeited
|
(11,241
|
)
|
$
|
27.52
|
|||
|
Outstanding-December
31, 2004
|
730,447
|
$
|
27.49
|
||||
|
Exercised
|
(291,177
|
)
|
$
|
27.48
|
|||
|
Forfeited
|
-
|
-
|
|||||
|
Outstanding-
December 31, 2005
|
439,270
|
$
|
27.53
|
||||
|
Exercised
|
(53,330
|
)
|
$
|
27.52
|
|||
|
Forfeited
|
-
|
-
|
|||||
|
Outstanding-
December 31, 2006
|
385,940
|
$
|
27.56
|
||||
No
stock
options have been granted since August 2002, and all options were fully vested
in August 2005. The options expire ten years after the grant date. At December
31, 2006, all outstanding options were currently exercisable at prices ranging
from $25.50-$29.60, and had a weighted-average remaining contractual life of
4.9
years.
All
options were granted with exercise prices equal to the fair market value of
SCANA’s common stock on the respective grant dates; therefore, no compensation
expense was recognized in connection with such grants. If the Company had
recognized compensation expense for the issuance of options based on the fair
value method described in SFAS 123(R), pro forma earnings available for the
common shareholder for the years ended December 31, 2005 and 2004 would have
been as follows:
|
|
|
2005
|
2004
|
|
||||
|
Earnings
Available for Common Shareholder-as reported (millions)
|
|
$
|
250.8
|
|
$
|
225.2
|
|
|
|
Earnings
Available for Common Shareholder-pro forma (millions)
|
|
250.6
|
|
|
224.1
|
|
||
The
exercise of stock options during the period was satisfied using original issue
shares of SCANA’s common stock. Cash and the related tax benefits realized from
stock option exercises during the period were retained at SCANA. Beginning
in 2007, the Company will satisfy the exercise of stock options using open
market purchases of common stock, rather than original issue of shares. The
Company estimates that 200,000 common shares will be repurchased in 2007 due
to
the exercise of stock options.
4. LONG-TERM
DEBT
Long-term
debt by type with related weighted average interest rates and maturities is
as
follows:
|
|
Weighted-Average
|
Maturity
|
December 31,
|
||||||||||
|
|
Interest
Rate
|
Date
|
2006
|
2005
|
|||||||||
|
|
Millions
of dollars
|
||||||||||||
|
First
Mortgage Bonds (secured)
|
6.00
|
%
|
2009-2036
|
$
|
1,675
|
$
|
1,550
|
||||||
|
First &
Refunding Mortgage Bonds (secured)
|
9.00
|
%
|
2006
|
-
|
131
|
||||||||
|
GENCO
Notes (secured)
|
5.92
|
%
|
2011-2024
|
123
|
127
|
||||||||
|
Industrial
and Pollution Control Bonds
|
5.24
|
%
|
2012-2032
|
156
|
156
|
||||||||
|
Other
|
2007-2014
|
80
|
97
|
||||||||||
|
Total
debt
|
2,034
|
2,061
|
|||||||||||
|
Current
maturities of long-term debt
|
(13
|
)
|
(183
|
)
|
|||||||||
|
Unamortized
discount
|
(13
|
)
|
(22
|
)
|
|||||||||
|
Total
long-term debt, net
|
$
|
2,008
|
$
|
1,856
|
|||||||||
The
annual amounts of long-term debt maturities for the years 2007 through 2011
are
summarized as follows:
|
Year
|
|
Millions
of dollars
|
|
|
|
|
||||
|
2007
|
|
$
|
13
|
|
|
2008
|
|
|
13
|
|
|
2009
|
|
|
138
|
|
|
2010
|
|
|
16
|
|
|
2011
|
|
|
171
|
|
Under
an
agreement with the South Carolina Transportation Infrastructure Bank (the Bank)
and the South Carolina Department of Transportation (SCDOT), SCE&G borrowed
an aggregate $59 million from the Bank to construct a roadbed for SCDOT in
connection with the Lake Murray back-up dam project. Such borrowings are being
repaid interest-free over ten years. At December 31, 2006 and 2005,
SCE&G had $44.3 million and $50.2 million outstanding under the
agreement, respectively.
Substantially
all of SCE&G's and GENCO's electric utility plant is pledged as collateral
in connection with long-term debt.
5. LINES
OF CREDIT AND SHORT-TERM BORROWINGS
Details
of lines of credit and short-term borrowings at December 31, 2006 and 2005,
are as follows:
|
|
|
2006
|
2005
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Lines
of credit (total and unused)
|
|
|
|
|
|
||
|
Committed
|
|
$
|
650
|
$
|
525
|
|
|
|
Uncommitted
(a)
|
|
|
78
|
|
78
|
||
|
Short-term
borrowings outstanding
|
|
|
|
|
|
||
|
Commercial
paper (270 or fewer days)
|
|
$
|
362.2
|
$
|
303.1
|
|
|
|
Weighted
average interest rate
|
|
|
5.38
|
%
|
|
4.40
|
%
|
(a)
Line
of credit that either SCE&G or SCANA may use.
The
Company pays fees to banks as compensation for maintaining committed lines
of
credit.
Nuclear
and fossil fuel inventories and emission allowances are financed through the
issuance by Fuel Company of short-term commercial paper. All commercial paper
borrowings are supported by five-year revolving credit facilities which expire
on December 19, 2011.
Fuel
Company commercial paper outstanding totaled $123.7 million and
$106.7 million at December 31, 2006 and 2005, respectively, at
weighted average interest rates of 5.38% and 4.39%, respectively.
SCE&G’s
commercial paper outstanding totaled $238.5 million and $196.4 million
at December 31, 2006 and 2005, respectively, at weighted average interest
rates of 5.38% and 4.40%, respectively.
6. RETAINED
EARNINGS
SCE&G’s
Restated Articles of Incorporation contain provisions that, under certain
circumstances, which SCE&G considers to be remote, could limit the payment
of cash dividends on its common stock.
With
respect to hydroelectric projects, the Federal Power Act requires the
appropriation of a portion of certain earnings therefrom. At December 31,
2006, $54 million of retained earnings were restricted by this requirement
as to
payment of cash dividends on common stock.
7. PREFERRED
STOCK
Retirements
under sinking fund requirements are at par values. The aggregate of the annual
amounts of purchase or sinking fund requirements for preferred stock for the
years 2007 through 2011 is $2.5 million. The call premium of the respective
series of preferred stock in no case exceeds the amount of the annual dividend.
At December 31, 2006 SCE&G had shares of preferred stock authorized and
available for issuance as follows:
|
Par
Value
|
Authorized
|
Available
for Issuance
|
|
$100
|
1,000,000
|
-
|
|
$
50
|
592,405
|
300,000
|
|
$
25
|
2,000,000
|
2,000,000
|
Preferred
Stock (Not subject to purchase or sinking funds)
For
each
of the three years ended December 31, 2006, SCE&G had outstanding
1,000,000 shares of 6.52% $100 par and 125,209 shares of 5.00% $50 par
Cumulative Preferred Stock (not subject to purchase or sinking
funds).
Preferred
Stock (Subject to purchase or sinking funds)
Changes
in “Total Preferred Stock (Subject to purchase or sinking funds)” during 2006,
2005 and 2004 are summarized as follows:
|
|
Series
|
||||||||||||
|
|
4.50%,
4.60% (A)
&
5.125%
|
4.60%
(B)
&
6.00%
|
Total
Shares
|
Millions
of Dollars
|
|||||||||
|
Redemption
Price
|
$51.00
|
$50.50
|
|||||||||||
|
Balance
at December 31, 2003
|
81,034
|
112,561
|
193,595
|
$
|
9.7
|
||||||||
|
Shares
Redeemed-$50 par value
|
(2,516
|
)
|
(6,600
|
)
|
(9,116
|
)
|
(0.5
|
)
|
|||||
|
Balance
at December 31, 2004
|
78,518
|
105,961
|
184,479
|
9.2
|
|||||||||
|
Shares
Redeemed-$50 par value
|
(1,475
|
)
|
(6,600
|
)
|
(8,075
|
)
|
(0.4
|
)
|
|||||
|
Balance
at December 31, 2005
|
77,043
|
99,361
|
176,404
|
8.8
|
|||||||||
|
Shares
Redeemed-$50 par value
|
(2,608
|
)
|
(6,600
|
)
|
(9,208
|
)
|
(0.5
|
)
|
|||||
|
Balance
at December 31, 2006
|
74,435
|
92,761
|
167,196
|
$
|
8.3
|
||||||||
8. INCOME
TAXES
Total
income tax expense (benefit) attributable to income (before cumulative effect
of
accounting change) for 2006, 2005 and 2004 is as follows:
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
|
|
Millions
of dollars
|
|
|||||||
|
Current
taxes:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
$
|
69.6
|
$
|
(8.4
|
)
|
$
|
47.4
|
|
|
|
State
|
|
|
5.3
|
9.5
|
|
|
(4.4
|
)
|
||
|
Total
current taxes
|
|
|
74.9
|
1.1
|
|
|
43.0
|
|
||
|
Deferred
taxes, net:
|
|
|
|
|
|
|
|
|||
|
Federal
|
|
|
8.6
|
(7.5
|
)
|
|
28.1
|
|
||
|
State
|
|
|
5.2
|
(9.8
|
)
|
|
4.1
|
|
||
|
Total
deferred taxes
|
|
|
13.8
|
(17.3
|
)
|
|
32.2
|
|
||
|
Investment
tax credits:
|
|
|
|
|
|
|
|
|||
|
Deferred-state
|
|
|
5.0
|
5.1
|
|
|
10.0
|
|
||
|
Amortization
of amounts deferred-state
|
|
|
(3.3
|
)
|
(1.9
|
)
|
|
(2.1
|
)
|
|
|
Amortization
of amounts deferred-federal
|
|
|
(2.7
|
)
|
(2.7
|
)
|
|
(3.6
|
)
|
|
|
Total
investment tax credits
|
|
|
(1.0
|
)
|
0.5
|
|
|
4.3
|
|
|
|
Synthetic
fuel tax credits - federal
|
|
|
-
|
(134.2
|
)
|
|
40.5
|
|
||
|
Total
income tax expense (benefit)
|
|
$
|
87.7
|
$
|
(149.9
|
)
|
$
|
120.0
|
|
|
The
difference between actual income tax expense (benefit) and that amount
calculated from the application of the statutory 35% federal income tax rate
to
pre-tax income (before cumulative effect of accounting change) is reconciled
as
follows:
|
|
|
2006
|
2005
|
2004
|
|
|||||
|
|
|
Millions
of dollars
|
|
|||||||
|
Net
income
|
|
$
|
230.0
|
$
|
258.1
|
|
$
|
232.5
|
|
|
|
Income
tax expense (benefit)
|
|
|
87.7
|
(149.9
|
)
|
|
120.0
|
|
||
|
Minority
interest
|
|
|
7.0
|
5.5
|
|
|
10.3
|
|
||
|
Total
pre-tax income
|
|
|
324.7
|
113.7
|
|
|
362.8
|
|
||
|
Income
taxes on above at statutory federal income tax rate
|
|
$
|
113.6
|
$
|
39.8
|
|
$
|
127.0
|
|
|
|
Increases
(decreases) attributed to:
|
|
|
|
|
|
|
|
|||
|
State
income taxes (less federal income tax effect)
|
|
|
7.9
|
1.9
|
|
|
4.9
|
|
||
|
Synthetic
fuel tax credits
|
|
|
(33.5
|
)
|
(181.9
|
)
|
|
(2.9
|
)
|
|
|
Allowance
for equity funds used during construction
|
|
|
0.1
|
-
|
|
|
(5.0
|
)
|
||
|
Non-taxable
recovery of Lake Murray back-up dam project carrying costs
|
|
|
(2.3
|
)
|
(3.8
|
)
|
|
-
|
|
|
|
Amortization
of federal investment tax credits
|
|
|
(2.7
|
)
|
(2.7
|
)
|
|
(3.6
|
)
|
|
|
Amended
returns for prior years
|
|
|
-
|
(2.1
|
)
|
|
-
|
|
||
|
Other
differences, net
|
|
|
4.6
|
(1.1
|
)
|
|
(0.4
|
)
|
||
|
Total
income tax expense (benefit)
|
|
$
|
87.7
|
$
|
(149.9
|
)
|
$
|
120.0
|
|
|
The
tax
effects of significant temporary differences comprising the Company’s net
deferred tax liability of $788.2 million at December 31, 2006 and
$778.2 million at December 31, 2005 are as follows:
|
|
|
2006
|
2005
|
|
|||
|
|
|
Millions
of dollars
|
|
||||
|
Deferred
tax assets:
|
|
|
|
|
|
||
|
Nondeductible
reserves
|
|
$
|
90.6
|
|
$
|
72.1
|
|
|
Unamortized
investment tax credits
|
|
|
58.2
|
|
|
59.2
|
|
|
Federal
alternative minimum tax credit carryforward
|
|
|
22.1
|
|
|
44.0
|
|
|
Deferred
compensation
|
|
|
25.0
|
|
|
25.4
|
|
|
Unbilled
revenue
|
|
|
10.5
|
|
|
16.4
|
|
|
Other
|
|
|
9.0
|
|
|
8.6
|
|
|
Total
deferred tax assets
|
|
|
215.4
|
|
|
225.7
|
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
828.9
|
|
|
824.5
|
|
|
Pension
plan income
|
|
|
74.1
|
|
|
110.5
|
|
|
Deferred
employee benefit plan costs
|
50.5
|
-
|
|||||
|
Deferred
fuel costs
|
|
|
25.7
|
|
|
44.5
|
|
|
Other
|
|
|
24.4
|
|
|
24.4
|
|
|
Total
deferred tax liabilities
|
|
|
1,003.6
|
|
|
1,003.9
|
|
|
Net
deferred tax liability
|
|
$
|
788.2
|
|
$
|
778.2
|
|
The
Internal Revenue Service has completed examinations of the Company's
consolidated federal income tax returns through 2004, and the Company’s tax
returns through 2001 are closed for additional assessment. The IRS is currently
examining S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which the
Company has an interest, for the 2004 tax year. The Company does not anticipate
that any adjustments which might result from the examination will have a
material impact on the earnings or the financial position of the Company. The
Company continues to believe that all of its synthetic fuel tax credits have
been properly claimed.
9. FINANCIAL
INSTRUMENTS
Financial
instruments for which the carrying amount does not equal estimated fair value
at
December 31, 2006 and 2005 were as follows:
|
|
|
2006
|
2005
|
|
||||||||||
|
|
|
Carrying
Amount
|
Estimated
Fair
Value
|
Carrying
Amount
|
Estimated
Fair
Value
|
|
||||||||
|
|
|
Millions
of dollars
|
|
|||||||||||
|
Long-term
debt
|
|
$
|
2,021.0
|
$
|
2,068.0
|
|
$
|
2,038.3
|
|
$
|
2,125.8
|
|
||
|
Preferred
stock (subject to purchase or sinking funds)
|
|
|
8.3
|
7.8
|
|
|
8.8
|
|
|
8.2
|
|
|||
The
following methods and assumptions were used to estimate the fair value of
financial instruments:
Fair
values of long-term debt are based on quoted market prices of the instruments
or
similar instruments. For debt instruments for which no quoted market prices
are
available, fair values are based on net present value calculations. Early
settlement of long-term debt may not be possible or may not be considered
prudent.
The
fair
value of preferred stock (subject to purchase or sinking funds) is estimated
using market prices.
Potential
taxes and other expenses that would be incurred in an actual sale or settlement
have not been considered.
The
Company’s regulated gas operations hedge gas purchasing activities using
over-the-counter options and swaps and NYMEX futures and options. The Company’s
tariffs include a purchased gas adjustment (PGA) clause that provides for the
recovery of actual gas costs incurred. The SCPSC has ruled that the results
of
these hedging activities are to be included in the PGA. As such, the cost of
related derivatives utilized to hedge gas purchasing activities are recoverable
through the weighted average cost of gas calculation. The offset to the charge
in fair value of these derivatives is recorded as a regulatory asset or
liability.
In
anticipation of the issuance of debt, the Company may use interest rate lock
or
similar agreements to manage interest rate risk. These arrangements are
designated as cash flow hedges. As such, payments received or made upon
termination of such agreements are amortized to interest expense over the term
of the underlying debt. As
permitted by SFAS 104 “Statement
of Cash Flows - Net Reporting of Certain Cash Receipts and Cash Payments and
Classification of Cash Flows from Hedging Transactions,” payments
received or made are classified as a financing activity in the consolidated
statement of cash flows.
10. COMMITMENTS
AND CONTINGENCIES
A. Nuclear
Insurance
The
Price-Anderson Indemnification Act deals with public liability for a nuclear
incident and establishes the liability limit for third-party claims associated
with any nuclear incident at $10.5 billion. Each reactor licensee is
currently liable for up to $100.6 million per reactor owned for each
nuclear incident occurring at any reactor in the United States, provided that
not more than $15 million of the liability per reactor would be assessed
per year. SCE&G’s maximum assessment, based on its two-thirds ownership of
Summer Station, would be approximately $67.1 million per incident, but not
more than $15 million per year.
The
Company currently maintains policies (for itself and on behalf of Santee Cooper,
the one-third owner of Summer Station) with Nuclear Electric Insurance Limited.
The policies, covering the nuclear facility for property damage, excess property
damage and outage costs, permit retrospective assessments under certain
conditions to cover insurer’s losses. Based on the current annual premium, the
Company’s portion of the retrospective premium assessment would not exceed
$14.1 million.
To
the extent
that insurable claims for property damage, decontamination, repair and
replacement and other costs and expenses arising from a nuclear incident at
Summer Station exceed the policy limits of insurance, or to the extent such
insurance becomes unavailable in the future, and to the extent that SCE&G’s
rates would not recover the cost of any purchased replacement power, the Company
will retain the risk of loss as a self-insurer. The Company has no reason to
anticipate a serious nuclear incident at Summer Station. However, if such an
incident were to occur, it would have a material adverse impact on the Company’s
results of operations, cash flows and financial position.
B. Environmental
In
March
2005 the Environmental Protection Agency (EPA) issued a final rule known as
the
Clean Air Interstate Rule (CAIR). CAIR requires the District of Columbia and
28
states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide
emissions in order to attain mandated state levels. The Company has petitioned
the United States Court of Appeals for the District of Columbia Circuit to
review CAIR. Several other electric utilities have filed separate petitions.
The
petitioners seek a change in the method CAIR uses to allocate sulfur dioxide
emission allowances to a method the petitioners believe is more equitable.
The
Company believes that installation of additional air quality controls will
be
needed to meet the CAIR requirements. Compliance plans and cost to comply with
the rule will be determined once the Company completes its review. Such costs
will be material and are expected to be recoverable through rates.
In
March
2005, the EPA issued a final rule establishing a mercury emissions cap and
trade
program for coal-fired power plants that requires limits to be met in two
phases, in 2010 and 2018. Although the Company expects to be able to meet the
Phase I limits through those measures it already will be taking to meet its
CAIR
obligations, it is uncertain as to how the Phase II limits will be met. Assuming
Phase II limits remain unchanged, installation of additional air quality
controls likely will be required to comply with the rule’s Phase II mercury
emission caps. Final compliance plans and costs to comply with the rule are
still under review. Such costs will be material and are expected to be
recoverable through rates.
SCE&G
has been named, along with 29 others, by the Environmental Protection Agency
(EPA) as a potentially responsible party (PRP) at the Carolina Transformer
Superfund site located in Fayetteville, North Carolina. The Carolina
Transformer Company (CTC) conducted an electrical transformer rebuilding and
repair operation at the site from 1967 to 1984. During that time,
SCE&G occasionally used CTC for the repair of existing transformers,
purchase of new transformers and sale of used transformers. In 1984, EPA
initiated a cleanup of PCB-contaminated soil and groundwater at the site.
EPA reports that it has spent $36 million to date. Although a basis for
the allocation of clean-up costs among the PRPs is unclear, SCE&G does not
believe that its involvement at this site would result in an allocation of
costs
that would have a material adverse impact on its results of operations, cash
flows or financial condition. Any cost allocated to SCE&G arising from the
remediation of this site, net of insurance recoveries, if any, is expected
to be
recoverable through rates.
SCE&G
has been named, along with 53 others, by the EPA as a PRP at the Alternate
Energy Resources, Inc. (AER) Superfund site located in Augusta, Georgia.
The EPA placed the site on the National Priorities List on April 19, 2006.
AER
conducted hazardous waste storage and treatment operations from 1975 to 2000,
when the site was abandoned. While operational, AER processed fuels from
waste oils, treated industrial coolants and oil/water emulsions, recycled
solvents and blended hazardous waste fuels. During that time, SCE&G
occasionally used AER for the processing of waste solvents, oily rags and oily
wastewater. EPA and the State of Georgia have documented that a release or
releases have occurred at the site leading to contamination of groundwater,
surface water and soils. EPA and the State of Georgia have conducted a
preliminary assessment and site inspection. The site has not been cleaned up
nor
has a cleanup cost been estimated. Although a basis for the allocation of
clean-up costs among the PRPs is unclear, SCE&G does not believe that its
involvement at this site would result in an allocation of costs that would
have
a material adverse impact on its results of operations, cash flows or financial
condition. Any cost allocated to SCE&G arising from the remediation of this
site, net of insurance recoveries, if any, is expected to be recoverable through
rates.
At
the
Company, site assessment and cleanup costs are deferred and amortized with
recovery provided through rates. Deferred amounts, net of amounts previously
recovered through rates and insurance settlements, totaled $17.9 million at
December 31, 2006. The deferral includes the estimated costs associated
with the following matters.
The
Company owns a decommissioned MGP site in the Calhoun Park area of Charleston,
South Carolina. The Company anticipates that remediation for contamination
at
the site will be completed in 2007, with certain monitoring and retreatment
activities continuing until 2011. As of December 31, 2006, the Company had
spent
$22.3 million to remediate the site and expects to spend an additional $1.1
million prior to entering a monitoring and reporting stage. In addition, the
National Park Service of the Department of the Interior made an initial demand
to the Company for payment of $9.1 million for certain costs and damages
relating to this site. SCE&G expects to recover any cost arising from the
remediation of this site through rates.
The
Company owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. One of the sites has been remediated
and will undergo routine monitoring until released by DHEC. The other sites
are
currently being investigated under work plans approved by DHEC. The Company
anticipates that major remediation activities for the three sites will be
completed in 2011. As of December 31, 2006, the Company has spent
approximately $4.8 million related to these three sites, and expects to spend
an
additional $11.2 million. SCE&G expects to recover any cost arising
from the remediation of these sites through rates.
C.
Franchise Agreements
See
Note 1B for a discussion of the electric and gas franchise agreements
between the Company and the cities of Columbia and Charleston.
D. Claims
and Litigation
In
August
2003, SCE&G was served as a co-defendant in a purported class action lawsuit
styled as Collins v. Duke Energy Corporation, Progress Energy Services Company,
and SCE&G in South Carolina's Circuit Court of Common Pleas for the Fifth
Judicial Circuit. Since that time, the plaintiffs have dismissed defendants
Duke
Energy and Progress Energy and are proceeding against SCE&G only. The
plaintiffs are seeking damages for the alleged improper use of electric
transmission and distribution easements but have not asserted a dollar amount
for their claims. Specifically, the plaintiffs contend that the licensing of
attachments on electric utility poles, towers and other facilities to nonutility
third parties or telecommunication companies for other than the electric
utility’s internal use along the electric transmission and distribution line
rights-of-way constitutes a trespass. It is anticipated that this case may
not
go to trial before 2008. SCANA and SCE&G are confident of the propriety of
SCE&G’s actions and intend to mount a vigorous defense. SCANA and SCE&G
further believe that the resolution of these claims will not have a material
adverse impact on their results of operations, cash flows or financial
condition.
In
May 2004, SCANA and SCE&G were served with a purported class action
lawsuit styled as Douglas E. Gressette, individually and on behalf of other
persons similarly situated v. South Carolina Electric & Gas Company and
SCANA Corporation. The case was filed in South Carolina's Circuit Court of
Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges SCANA and
SCE&G made improper use of certain easements and rights-of-way by allowing
fiber optic communication lines and/or wireless communication equipment to
transmit communications other than SCANA’s and SCE&G’s electricity-related
internal communications. The plaintiff asserted causes of action for unjust
enrichment, trespass, injunction and declaratory judgment. The plaintiff did
not
assert a specific dollar amount for the claims. SCANA and SCE&G believe
their actions are consistent with governing law and the applicable documents
granting easements and rights-of-way. The Circuit Court granted SCANA’s and
SCE&G’s motion to dismiss and issued an order dismissing the case in June
2005. The
plaintiff appealed to the South Carolina Supreme Court. The Supreme Court
overruled the Circuit Court in October 2006 and returned the case to the Circuit
Court for further consideration. It is anticipated that this case may not go
to
trial before 2008. SCANA and SCE&G will continue to mount a vigorous defense
and believes that the resolution of these claims will not have a material
adverse impact on its results of operations, cash flows or financial condition.
A
complaint was filed in October 2003 against SCE&G by the State of South
Carolina alleging that SCE&G violated the Unfair Trade Practices Act by
charging municipal franchise fees to some customers residing outside a
municipality's limits. The complaint alleged that SCE&G failed to obey,
observe or comply with the lawful order of the SCPSC by charging franchise
fees
to those not residing within a municipality. The complaint sought restitution
to
all affected customers and penalties of up to $5,000 for each separate
violation. The claim against SCE&G has been settled by an agreement between
the parties, and the settlement has been approved by South
Carolina’s Circuit Court of Common Pleas for the Fifth Judicial Circuit. In
addition, SCE&G filed a petition with the SCPSC in October 2003 pursuant to
S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its
jurisdiction to investigate the operation of the municipal franchise fee
collection requirements applicable to SCE&G’s electric and gas service, to
approve SCE&G’s efforts to correct any past franchise fee billing errors, to
adopt improvements in the system which will reduce such errors in the future,
and to adopt any regulation that the SCPSC deems just and proper to regulate
the
franchise fee collection process. A hearing on this petition has not been
scheduled. The Company believes that the resolution of these matters will not
have a material adverse impact on its results of operations, cash flows or
financial condition.
The
Company is also engaged in various other claims and litigation incidental to
its
business operations which management anticipates will be resolved without a
material adverse impact on the Company’s results of operations, cash flows or
financial condition.
E. Settlement
Related to Power Marketing Practices
On
January 18, 2007, FERC approved a settlement with SCE&G regarding the use of
SCE&G’s electric transmission system by its power marketing division.
SCE&G identified, investigated and self-reported instances of improper
utilization of network transmission services, rather than point-to-point
transmission services, for purchases and sales of electricity in violation
of
SCE&G’s open access transmission tariff and applicable FERC orders under the
Federal Power Act that prohibit the use of network transmission service in
support of certain “off-system” sales.
As
part
of the settlement, SCE&G agreed that it would not retain any benefit derived
from the transactions. SCE&G paid a $9 million penalty to the U.S. Treasury.
Additionally, SCE&G agreed to credit an additional $1.4 million to benefit
retail native load ratepayers and SCE&G’s non-affiliated firm transmission
customers. The credit to the retail native load ratepayers was applied toward
the fuel clause mechanism in January 2007. The credit to the non-affiliated
firm
transmission customers was refunded directly to those customers. An additional
$0.4 million was credited to transmission revenue to the benefit of SCE&G’s
retail rate payers. The effects of the settlement were accrued in
2006.
F. Operating
Lease Commitments
The
Company is obligated under various operating leases with respect to office
space, furniture and equipment. Leases expire at various dates through 2009.
Rent expense totaled approximately $12.8 million, $11.7 million and
$9.9 million in 2006, 2005 and 2004, respectively. Future minimum rental
payments under such leases are as follows:
|
|
|
Millions
of dollars
|
|
|
|
2007
|
|
$
|
27
|
|
|
2008
|
|
13
|
|
|
|
2009
|
|
9
|
|
|
|
Thereafter
|
-
|
|||
|
|
|
$
|
49
|
|
At
December 31, 2006, minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$5.7 million.
G. Purchase
Commitments
The
Company is obligated for purchase commitments that expire at various dates
through 2034. Amounts expended for coal supply, nuclear fuel contracts,
construction projects and other commitments totaled $526.0 million,
$439.4 million and $348.3 million in 2006, 2005 and 2004,
respectively. Future payments under such purchase commitments are as
follows:
|
|
|
Millions
of dollars
|
|
|
|
2007
|
|
$
|
689
|
|
|
2008
|
|
359
|
|
|
|
2009
|
|
489
|
|
|
|
2010
|
|
49
|
|
|
|
2011
|
|
18
|
|
|
|
Thereafter
|
|
106
|
|
|
|
|
|
$
|
1,710
|
|
In
addition, included in purchase commitments are customary purchase orders under
which the Company has the option to utilize certain vendors without the
obligation to do so. The Company may terminate such commitments without
penalty.
H. Asset
Retirement Obligations
In
accordance with SFAS 143, “Accounting
for Asset Retirement Obligations,”
as
interpreted by FIN 47, “Accounting
for Conditional Asset Retirement Obligations,”
the
Company recognizes a liability for the fair value of an ARO when incurred if
the
fair value of the liability can be reasonably estimated. Uncertainty about
the
timing or method of settlement of a conditional ARO is factored into the
measurement of the liability when sufficient information exists, but such
uncertainty is not a basis upon which to avoid liability recognition.
SFAS 143
applies to the legal obligation associated with the retirement of long-lived
tangible assets that result from their acquisition, construction, development
and normal operation and relates primarily to the Company’s regulated utility
operations. As of December 31, 2006, the Company has recorded an ARO of
approximately $92 million for nuclear plant decommissioning (see Note 1G) and
an
ARO of approximately $185 million for other conditional obligations related
to
generation, transmission and distribution properties, including gas pipelines.
All of the amounts recorded are based upon estimates which are subject to
varying degrees of imprecision, particularly since such payments will be made
many years in the future.
A
reconciliation of the beginning and ending aggregate carrying amount of asset
retirement obligations is as follows:
|
Millions
of dollars
|
|
2006
|
2005
|
|
|||
|
Beginning
balance
|
|
$
|
309
|
|
$
|
124
|
|
|
Liabilities
incurred
|
1
|
-
|
|||||
|
Liabilities
settled
|
(1
|
)
|
-
|
||||
|
Accretion
expense
|
|
|
16
|
|
|
7
|
|
|
Revisions
in estimated cash flows
|
(46
|
)
|
-
|
||||
|
Adoption
of FIN 47
|
|
|
-
|
|
|
178
|
|
|
Ending
Balance
|
|
$
|
279
|
|
$
|
309
|
|
Revisions
in estimated cash flows relate to the estimated ARO associated with
decommissioning Summer Station. The reduction is primarily related to the
expectation of lower decommissioning cost escalations than had been assumed
in
the prior cash flow analysis.
11. SEGMENT
OF BUSINESS INFORMATION
The
Company’s reportable segments are Electric Operations and Gas Distribution. The
accounting policies of the segments are the same as those described in the
summary of significant accounting policies. The Company records intersegment
sales and transfers of electricity and gas based on rates established by the
appropriate regulatory authority. Nonregulated sales and transfers are recorded
at current market prices.
Electric
Operations is primarily engaged in the generation, transmission, and
distribution of electricity, and is regulated by the SCPSC and FERC. Gas
Distribution is engaged in the purchase and sale, primarily at retail, of
natural gas, and is regulated by the SCPSC.
Disclosure
of Reportable Segments (Millions of dollars)
|
2006
|
Electric
Operations
|
Gas
Distribution
|
All
Other
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|||||||||||
|
Customer
Revenue
|
$
|
1,886
|
$
|
505
|
-
|
-
|
$
|
2,391
|
||||||||
|
Intersegment
Revenue
|
-
|
3
|
-
|
(3
|
)
|
-
|
||||||||||
|
Operating
Income (Loss)
|
456
|
25
|
-
|
(13
|
)
|
468
|
||||||||||
|
Interest
Expense
|
15
|
-
|
-
|
125
|
140
|
|||||||||||
|
Depreciation and
Amortization
|
268
|
18
|
-
|
-
|
286
|
|||||||||||
|
Segment
Assets
|
5,520
|
440
|
-
|
1,666
|
7,626
|
|||||||||||
|
Expenditures
for Assets
|
304
|
83
|
-
|
25
|
412
|
|||||||||||
|
Deferred
Tax Assets
|
n/a
|
n/a
|
-
|
19
|
19
|
|||||||||||
|
2005
|
Electric
Operations
|
Gas
Distribution
|
All
Other
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|||||||||||
|
Customer
Revenue
|
$
|
1,912
|
$
|
509
|
-
|
-
|
$
|
2,421
|
||||||||
|
Intersegment
Revenue
|
-
|
1
|
-
|
$
|
(1
|
)
|
-
|
|||||||||
|
Operating
Income (Loss)
|
299
|
16
|
-
|
(3
|
)
|
312
|
||||||||||
|
Interest
Expense
|
13
|
-
|
-
|
131
|
144
|
|||||||||||
|
Depreciation and
Amortization
|
450
|
15
|
-
|
-
|
465
|
|||||||||||
|
Segment
Assets
|
5,531
|
408
|
$
|
4
|
1,423
|
7,366
|
||||||||||
|
Expenditures
for Assets
|
280
|
58
|
-
|
(8
|
)
|
330
|
||||||||||
|
Deferred
Tax Assets
|
n/a
|
n/a
|
-
|
22
|
22
|
|||||||||||
|
2004
|
||||||||||||||||
|
Customer
Revenue
|
$
|
1,692
|
$
|
397
|
-
|
-
|
$
|
2,089
|
||||||||
|
Intersegment
Revenue
|
-
|
1
|
-
|
$
|
(1
|
)
|
-
|
|||||||||
|
Operating
Income (Loss)
|
550
|
14
|
-
|
(89
|
)
|
475
|
||||||||||
|
Interest
Expense
|
10
|
-
|
-
|
129
|
139
|
|||||||||||
|
Depreciation and
Amortization
|
208
|
13
|
-
|
-
|
221
|
|||||||||||
|
Segment
Assets
|
5,365
|
354
|
$
|
3
|
1,263
|
6,985
|
||||||||||
|
Expenditures
for Assets
|
389
|
35
|
-
|
15
|
439
|
|||||||||||
|
Deferred
Tax Assets
|
n/a
|
n/a
|
-
|
5
|
5
|
|||||||||||
Management
uses operating income to measure segment profitability for regulated operations
and evaluates utility plant, net, for its segments. As a result, the Company
does not allocate interest charges, income tax expense (benefit) or assets
other
than utility plant to its segments. Interest income is not reported by segment
and is not material. In accordance with SFAS 109, the Company’s deferred
tax assets are netted with deferred tax liabilities for reporting
purposes.
The
Consolidated Financial Statements report operating revenues which are comprised
of the reportable segments. Revenues from non-reportable segments are included
in Other Income. Therefore, the adjustments to total operating revenues remove
revenues from non-reportable segments. Segment Assets include utility plant,
net
for all reportable segments. As a result, adjustments to assets include
non-utility plant and non-fixed assets for the segments. Adjustments to Interest
Expense, Expenditures for Assets and Deferred Tax Assets include the totals
from
the Company that are not allocated to the segments.
12. QUARTERLY
FINANCIAL DATA (UNAUDITED)
|
2006
Millions of dollars
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Annual
|
|
|||||||||
|
Total
operating revenues
|
$
|
592
|
$
|
553
|
$
|
664
|
$
|
582
|
$
|
2,391
|
|
|||||
|
Operating
income
|
103
|
113
|
159
|
93
|
468
|
|
||||||||||
|
Income
before cumulative effect of accounting change
|
46
|
53
|
93
|
38
|
230
|
|||||||||||
|
Cumulative
effect of accounting change, net of taxes (1)
|
4
|
-
|
-
|
-
|
4
|
|||||||||||
|
Net
income
|
50
|
53
|
93
|
38
|
234
|
|
||||||||||
|
2005
Millions of dollars
|
|
|
||||||||||||||
|
Total
operating revenues
|
|
$
|
573
|
|
$
|
523
|
|
$
|
696
|
|
$
|
629
|
|
$
|
2,421
|
|
|
Operating
income (loss)
|
|
|
(59
|
)
|
|
78
|
|
|
178
|
|
|
115
|
|
|
312
|
|
|
Net
income
|
|
|
52
|
|
|
40
|
|
|
106
|
|
|
60
|
|
|
258
|
|
(1)
The
cumulative effect of accounting change is attributable to the adoption of SFAS
123(R) in the first quarter of 2006. See
Note 3.
PART
II, ITEMS 9 AND 9A, PART III AND PART IV
SCANA
CORPORATION
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not
Applicable.
ITEM
9A. CONTROLS AND PROCEDURES
SCANA:
Evaluation
of Disclosure Controls and Procedures:
As
of
December 31, 2006, an evaluation was performed under the supervision and
with the participation of SCANA's management, including the Chief Executive
Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the
design and operation of the Company's disclosure controls and procedures. For
purposes of this evaluation, disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by SCANA in the reports that it files or submits under the
Securities Exchange Act of 1934 is accumulated and communicated to SCANA’s
management, including the CEO and CFO, as appropriate to allow timely
discussions regarding required disclosure. Based on that evaluation, SCANA's
management, including the CEO and CFO, concluded that SCANA's disclosure
controls and procedures were effective as of December 31, 2006. There has
been no change in SCANA's internal controls over financial reporting during
the
quarter ended December 31, 2006 that has materially affected or is
reasonably likely to materially affect SCANA's internal control over financial
reporting.
Management's
Evaluation of Internal Control Over Financial Reporting:
Pursuant
to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to
include in this Form 10-K an internal control report wherein management states
its responsibility for establishing and maintaining adequate internal control
structure and procedures for financial reporting and that it has assessed,
as of
December 31, 2006, the effectiveness of such structure and procedures. This
management report follows.
MANAGEMENT
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of SCANA Corporation (SCANA) is responsible for establishing and
maintaining adequate internal control over financial reporting. SCANA's internal
control system was designed by or under the supervision of SCANA’s management,
including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO),
to provide reasonable assurance to SCANA's management and board of directors
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles.
All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Also, the effectiveness of the internal control
over financial reporting may deteriorate in future periods due to either changes
in conditions or declining levels of compliance with policies or
procedures.
SCANA's
management assessed the effectiveness of SCANA's internal control over financial
reporting as of December 31, 2006. In making this assessment, SCANA used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control-Integrated Framework. Based
on
this assessment, SCANA's management believes that, as of December 31, 2006,
internal control over financial reporting is effective based on those
criteria.
SCANA's
independent registered public accounting firm has issued an attestation report
on the assessment of SCANA's internal control over financial reporting. This
report follows.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
SCANA
Corporation
We
have
audited management's assessment, included in the accompanying Management Report
On Internal Control Over Financial Reporting, that SCANA Corporation and
subsidiaries (the "Company") maintained effective internal control over
financial reporting as of December 31, 2006, based on the criteria
established in Internal Control-Integrated Framework issued by the Committee
of
Sponsoring Organizations of the Treadway Commission. The Company's management
is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.
We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A
company's internal control over financial reporting is a process designed by,
or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by
the
company's board of directors, management, and other personnel 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 (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures
of
the company are being made only in accordance with authorizations of management
and directors of the company; and (3) 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 the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented
or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In
our
opinion, management's assessment that SCANA Corporation and subsidiaries
maintained effective internal control over financial reporting as of
December 31, 2006, is fairly stated, in all material respects, based on the
criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Also in our
opinion, SCANA Corporation and subsidiaries maintained, in all material
respects, effective internal control over financial reporting as of
December 31, 2006, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission.
We
have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31,
2006, of SCANA Corporation and subsidiaries and our report dated February 28,
2007, expressed an unqualified opinion on those financial statements and
financial statement schedule and included an explanatory paragraph regarding
the Company's adoption of Statement of Financial Accounting Standards No.
158, "Employers' Accounting for Defined Benefit Pension and
Other Postretirement Plans."
/s/DELOITTE &
TOUCHE LLP
Columbia,
South Carolina
February
28, 2007
SCE&G:
Evaluation
of Disclosure Controls and Procedures:
As
of
December 31, 2006, an evaluation was performed under the supervision and
with the participation of SCE&G's management, including the CEO and CFO, of
the effectiveness of the design and operation of SCE&G's disclosure controls
and procedures. For purposes of this evaluation, disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by SCE&G in the reports
that it files or submits under the Securities Exchange Act of 1934 is
accumulated and communicated to SCE&G’s management, including the CEO and
CFO, as appropriate to allow timely discussions regarding required disclosure.
Based on that evaluation, SCE&G's management, including the CEO and CFO,
concluded that SCE&G's disclosure controls and procedures were effective as
of December 31, 2006. There has been no change in SCE&G's internal
controls over financial reporting during the quarter ended December 31,
2006 that has materially affected or is reasonably likely to materially affect
SCE&G's internal control over financial reporting.
ITEM
9B. OTHER INFORMATION
Not
applicable.
PART
III
ITEM
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT
SCANA:
A
list of SCANA's executive officers is in Part I of this annual report at
page 23. The other information required by Item 10 is incorporated herein by
reference to the captions "NOMINEES FOR DIRECTORS," "CONTINUING DIRECTORS,"
"BOARD MEETINGS -COMMITTEES OF THE BOARD," "GOVERNANCE INFORMATION - SCANA's
Code of Conduct & Ethics" and "OTHER INFORMATION-Section 16(a)
Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement
for the 2007 annual meeting of shareholders which will be filed with the SEC
pursuant to Regulation 14A, promulgated under the Securities Exchange Act
of 1934 within 120 days after the end of SCANA's fiscal year.
CODE
OF ETHICS
SCE&G:
SCE&G subscribes to the code of ethics of SCANA Corporation. All employees
(including the Chief Executive Officer, Chief Financial Officer and Controller)
and directors are required to abide by SCANA's Code of Conduct & Ethics
(the "Code") to ensure that SCANA's business is conducted in a consistently
legal and ethical manner. The Code forms the foundation of a comprehensive
process that includes compliance with corporate policies and procedures, an
open
relationship among colleagues that contributes to good business conduct, and
an
abiding belief in the integrity of SCANA's employees. SCANA's policies and
procedures cover all areas of business conduct, and require adherence to all
laws and regulations applicable to the conduct of SCANA's business.
The
full
text of the Code is published on the SCANA website, at www.scana.com,
under
the "Company Profile - code of conduct" caption, and a copy is also available
in
print upon request to the Corporate Secretary, SCANA Corporation, Mail Code
13-4, 1426 Main Street, Columbia, South Carolina 29201. SCANA intends to
disclose future amendments to, or waivers from, certain provisions of the Code
on its website within two business days following the date of such amendment
or
waiver.
DIRECTORS
The
directors listed below were elected April 27, 2006 to hold office until the
next
annual meeting of SCE&G's shareholders to be held on April 26,
2007. Each of the directors is also a director of SCANA. There are
no family relationships among any of SCE&G's directors and executive
officers.
|
William
C. Burkhardt (Age 69)*
Director
since 2000
|
|||
|
Mr.
Burkhardt has served as Chairman and Chief Executive Officer of Titan
Holdings, LLC, a real estate investment company, located in Raleigh,
North
Carolina, since May 2004. He was Chief Executive Officer of Capital
Bank,
in Raleigh, North Carolina, from October 2003 until retiring in May
2004.
From May 2000 until October 2003, Mr. Burkhardt pursued personal
interests. Mr. Burkhardt retired as President and Chief Executive
Officer
of Austin Quality Foods, Inc., a production and distribution company
of
baked snacks for the food industry, located in Cary, North Carolina,
in
May 2000, having served in that position since 1980. Mr. Burkhardt
is a
director of Capital Bank, in Raleigh, North Carolina and Plaza Belmont
II,
in Kansas City, Missouri.
|
|||
|
W.
Hayne Hipp (Age 66)
Director
since 1983
|
|||
|
Mr.
Hipp is a private investor. Prior to its acquisition in January 2006,
Mr. Hipp was Chairman, Chief Executive Officer and a director of The
Liberty Corporation, a broadcasting holding company headquartered
in
Greenville, South Carolina. He held these positions for more than
five
years.
|
|||
|
Harold
C. Stowe (Age 60)*
Director
since 1999
|
|||
|
Mr.
Stowe has been acting Dean of the Wall College of Business at Coastal
Carolina University in Conway, South Carolina since June 1, 2006.
Mr.
Stowe retired in February, 2005 as President of Canal Holdings, LLC,
a
forest products industry company, located in Conway, South Carolina.
Prior
to his retirement, Mr. Stowe had served as President of Canal Holdings,
LLC, and its predecessor company since March 1997. Mr. Stowe is a
director
of Ruddick Corporation, in Charlotte, North Carolina.
|
|||
|
G.
Smedes York (Age 66)
Director
since 2000
|
|||
|
Mr.
York is Chairman and Treasurer of York Properties, Inc., a full-service
commercial and residential real estate company, in Raleigh, North
Carolina. Mr. York has been associated with York Properties, Inc.
since
1970. Mr. York also is Chairman of the Board of York Simpson Underwood,
a
residential brokerage company, and of McDonald-York, Inc., a general
contractor, both in Raleigh, North Carolina.
|
|||
|
Bill
L. Amick (Age 63)
Director
since 1990
|
|||
|
Mr.
Amick is the Chairman of The Amick Company, a real estate development
company that develops residential and resort properties. On October
30,
2006, Mr. Amick retired from Amick Farms, Inc., Amick Processing,
Inc. and
Amick Broilers, Inc., a vertically integrated broiler operation.
Prior to
his retirement, he served as Chairman of the Board of the Amick entities
all of which are located in Batesburg, South Carolina. He held those
positions for more than five years. Mr.
Amick
is a director of Blue Cross and Blue Shield of South Carolina.
|
|||
|
Sharon
A. Decker (Age 49)
Director
since 2005
|
|||
|
Mrs.
Decker is the founder and has been the principal of The Tapestry
Group
LLC, a faith based consulting and communications company, located
in
Rutherfordton, North Carolina, since September 2004. Mrs. Decker
previously served as president of Tanner Holdings LLC and Doncaster,
apparel manufacturers, from August 1999 until September 2004. Mrs.
Decker
is a director of Coca-Cola Bottling Company Consolidated, Inc. and
Family
Dollar Stores, Inc., both in Charlotte, North Carolina.
|
|||
|
D.
Maybank Hagood (Age 45)*
Director
since 1999
|
|||
|
Mr.
Hagood has been President and Chief Executive Officer of Southern
Diversified Distributors, Inc., a provider of logistic and distribution
services, located in Charleston, South Carolina, since November,
2003.
Mr. Hagood also has been President and Chief Executive Officer of
William M. Bird and Company, Inc., a subsidiary of Southern Diversified
Distributors, Inc., a wholesale distributor of floor covering materials,
in Charleston, South Carolina, since 1993.
|
|||
|
William
B. Timmerman (Age 60)
Director
since 1991
|
|||
|
Mr.
Timmerman has been Chairman of the Board and Chief Executive Officer
of
SCANA since March 1, 1997. He has been President of SCANA since
December 13, 1995.
|
|||
|
James
A. Bennett (Age 45)
Director
since 1997
|
||||
|
Mr.
Bennett has been Executive Vice President and Director of Public
Affairs
of First Citizens Bank, located in Columbia, South Carolina, since
August
2002. Previously, he was President and Chief Executive Officer of
South
Carolina Community Bank, in Columbia, South Carolina, from May 2000
to
July 2002.
|
||||
|
Lynne
M. Miller (Age 55)
Director
since 1997
|
||||
|
Ms.
Miller has been an environmental consultant since her retirement
from
Quanta Capital Holdings, Inc., a specialty insurer, in August 2006.
From
August 2005 to August 2006 she was a Senior Business Consultant at
Quanta
Capital Holdings. From April 2004 through July 2005, she was President
of
Quanta Technical Services LLC. She was Chief Executive Officer of
Environmental Strategies Consulting LLC, a division of Quanta Technical
Services LLC, from September 2003 through March 2004. Ms. Miller
co-founded Environmental Strategies Corporation, an environmental
consulting firm in Reston, Virginia, in 1986, and served as President
from
1986 until 1995 and as Chief Executive Officer from 1995 until September
2003 when the firm was acquired by Quanta Capital Holdings, Inc.
and its
name was changed to Environmental Strategies Consulting LLC. Ms.
Miller is
a director of Adams National Bank, a subsidiary of Abigail Adams
National
Bancorp, Inc., in Washington, D.C.
|
||||
|
Maceo
K. Sloan (Age 57)*
Director
since 1997
|
||||
|
Mr.
Sloan is Chairman, President and Chief Executive Officer
of Sloan Financial Group, Inc., a financial holding company, and
Chairman,
Chief Executive Officer and Chief Investment Officer of both NCM
Capital
Management Group, Inc., and NCM Capital Advisers, Inc., investment
management companies, in Durham, North Carolina. He has held these
positions for more than five years. Mr. Sloan is a trustee of Teachers
Insurance Annuity Association-College Retirement Equity Fund (TIAA-CREF)
Funds Boards, Chairman of the Board of M&F Bancorp, Inc. and a
director of its subsidiary, Mechanics and Farmers Bank, in Durham,
North
Carolina.
|
||||
*Indicates
a member of the Audit Committee of SCE&G’s Board of Directors. Mr. Stowe has
been determined by SCE&G’s board of directors to be an audit committee
financial expert within the meaning of Item 407(d)(5) of Regulation S-K.
SCE&G’s board of directors has also determined that Mr. Stowe is independent
as defined by the New York Stock Exchange Listing Standards.
EXECUTIVE
OFFICERS
SCE&G's
officers are elected at the annual organizational meeting of the Board of
Directors and hold office until the next such organizational meeting, unless
(1)
a resignation is submitted, (2) the Board of Directors shall otherwise
determine, or (3) as provided in the By-laws of SCE&G.
|
Name
|
Age
|
Positions
Held During Past Five Years
|
Dates
|
|
W.
B. Timmerman
|
60
|
Chairman
of the Board and Chief Executive Officer
|
*-present
|
|
J.
E. Addison
|
46
|
Senior
Vice President and Chief Financial Officer
Vice
President - Finance
|
2006-present
*-2006
|
|
J.
C. Bouknight
|
54
|
Senior
Vice President-Human Resources
Vice
President Human Resources-Dan River, Inc.-Danville, VA
|
2004-present
*-2004
|
|
S.
D. Burch
|
49
|
Senior
Vice President, Fuel Procurement and Asset Management
Deputy
General Counsel and Assistant Secretary
|
2003-present
*-2003
|
|
S.
A. Byrne
|
47
|
Senior
Vice President-Generation, Nuclear and Fossil Hydro
Senior
Vice President-Nuclear Operations
|
2004-present
*-2004
|
|
P.
V. Fant
|
53
|
Senior
Vice President-Transmission Services
President
and Chief Operating Officer-CGTC (formerly SCPC and SCG)
Executive
Vice President-SCPC and SCG Pipeline
|
2004-present
2004-present
*-2004
|
|
K.
B. Marsh
|
51
|
President
and Chief Operating Officer
Senior
Vice President and Chief Financial Officer
President
and Chief Operating Officer-PSNC Energy
|
2006-present
*-2006
*-2003
|
|
F.
P. Mood, Jr.
|
69
|
Senior
Vice President, General Counsel and Assistant Secretary
Attorney,
Haynsworth Sinkler Boyd, P.A.
|
2005-present
*-2005
|
*
Indicates position held at least since March 1, 2002
SECTION
16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All
of
SCE&G's common stock is held by its parent, SCANA Corporation. The required
forms indicate that no equity securities of SCE&G are owned by its directors
and officers. Based solely on a review of the copies of such forms and
amendments furnished to SCE&G and written representations from its officers
and directors, SCE&G believes that its officers, directors and greater than
10% beneficial owners complied with all applicable Section 16(a) filing
requirements during 2006.
ITEM
11. EXECUTIVE COMPENSATION
SCANA:
The information required by Item 11 is incorporated herein by reference to
the
captions "EXECUTIVE COMPENSATION," "COMPENSATION COMMITTEE REPORT," "SUMMARY
COMPENSATION TABLE," "2006 GRANTS OF PLAN-BASED AWARDS," "OUTSTANDING
EQUITY AWARDS AT 2006 FISCAL YEAR END," "2006 OPTION EXERCISES AND STOCK
VESTED," "PENSION BENEFITS," "2006 NONQUALIFIED DEFERRED COMPENSATION,"
"POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL," and “DIRECTOR
COMPENSATION” in SCANA's definitive proxy statement for the 2007 annual
meeting of shareholders.
SCE&G:
The information required by Item 11 is as follows:
EXECUTIVE
COMPENSATION
Compensation
Committee Processes and Procedures
SCANA's
Human Resources Committee, which is comprised entirely of independent directors,
administers the senior executive compensation program for SCANA and
all of its subsidiaries, including SCE&G. Compensation decisions
for all senior executive officers and directors are approved by the Human
Resources Committee and recommended by the Committee to the full Board for
final
approval. The Committee considers recommendations from our Chairman and Chief
Executive Officer in setting compensation for senior executive officers and
directors.
In
addition to attendance by members of the Human Resources Committee, the
Committee’s meetings are also regularly attended by our Chairman and Chief
Executive Officer and our Senior Vice President of Human Resources. However,
at
each meeting the Committee also meets in executive session. The Chairman
of the
Committee reports the Committee’s recommendations on executive compensation to
the Board of Directors. Our Human Resources and Tax Departments support the
Human Resources Committee in its duties, and the Committee may delegate
authority to these departments to fulfill administrative duties relating
to our
compensation programs.
Under
its
charter, the Committee has the authority to retain, approve fees for, and
terminate advisors, consultants and others as it deems appropriate to assist
in
the fulfillment of its responsibilities. The Committee has, however,
historically chosen to use relevant information provided to us by management’s
consultant, Hewitt Associates. The Committee uses this information to assist
it
in carrying out its responsibilities for overseeing matters relating to
compensation plans and compensation of our senior executive officers. Using
information provided by a national compensation consultant helps to assure
the
Committee that our policies for compensation and benefits are competitive
and
aligned with utility and general industry practices.
Compensation
Discussion and Analysis
Objectives
and Philosophy of Executive Compensation
The
senior executive compensation program is designed to support our overall
objective of increasing shareholder value by:
| · |
Hiring
and retaining premier executive talent;
|
| · |
Having
a pay-for-performance philosophy that links total rewards to achievement
of corporate, business unit and individual goals, and places a substantial
portion of pay for senior executives
"at-risk";
|
| · |
Aligning
the interests of executives with the long-term interests of shareholders
through long-term equity-based incentive compensation;
and
|
| · |
Relating
the elements of the compensation program to focus on the proper balance
of
financial, customer-service, operational and strategic
goals.
|
We
have
designed our compensation program to reward senior executive officers for
their
individual and collective performance, and for our collective performance
in
achieving target goals for earnings per share and total shareholder return
and
other annual business objectives. We believe our program performs a vital
role
in keeping executives focused on improving our performance and enhancing
shareholder value while rewarding successful individual executive performance
in
a way that helps to assure retention.
The
following discussion provides an overview of our compensation program for
all of
our senior executive officers (a group of approximately ten people who are
at
the level of senior vice president and above), as well as a specific discussion
of compensation for our Chief Executive Officer, our Chief Financial Officer
and
the other executive officers named in the Summary Compensation Table that
follows this “Compensation Discussion and Analysis.” In this discussion, we
refer to the executives named in the Summary Compensation Table as “Named
Executive Officers.”
Principal
Components of Executive Compensation
During
2006, senior executive compensation consisted primarily of three key components:
base salary, short-term cash incentive compensation (under the Short-Term
Annual
Incentive Plan) and long-term equity-based incentive compensation (under
the
SCANA shareholder approved Long-Term Equity Compensation Plan). We also provide
various additional benefits to senior executive officers, including health,
life
and disability insurance plans, retirement plans, termination, severance
and
change in control arrangements, and perquisites. The Human Resources Committee
makes its decisions about how to allocate senior executive officer compensation
among base salary, short-term cash incentive compensation and long-term
equity-based incentive compensation on the basis of information provided
by our
compensation consultant, and our goals of remaining competitive with the
compensation practices of a group of surveyed companies and of linking
compensation to our corporate performance and individual senior executive
officer performance.
A
more
detailed discussion of each of these components of senior executive officer
compensation, the reasons for awarding such types of compensation, the
considerations in setting the amounts of each component of compensation,
the
amounts actually awarded for the periods indicated, and various other related
matters is set forth in the sections below.
SCANA
sponsors the Short-Term Annual Incentive Plan and the Long-Term Equity
Compensation Plan which are available to eligible senior executive officers
of
SCE&G. These plans are referred to herein as "our" plans.
Factors
Considered in Setting Senior Executive Officer
Compensation
Use
of Market Surveys and Peer Group Data
We
believe it is important to consider comparative market information about
compensation paid to executive officers of other companies in order to remain
competitive in the executive workforce marketplace. We want to be able to
attract and retain highly skilled and talented senior executive officers
who
have the ability to carry out our short-and long-term goals. To do so, we
must
be able to compensate them at levels that are competitive with compensation
offered by other companies in our business or geographic marketplace that
seek
similarly skilled and talented executives. Accordingly, we consider market
survey results in establishing target compensation levels for all components
of
compensation. The market survey information is provided to us every other
year
by our compensation consultant. In years in which our consultant does not
provide us with market survey information, our current process is to apply
an
aging factor to the prior year’s information with assistance from our consultant
based on its experience in the marketplace. Our most recent surveys were
performed in 2005.
Our
goal
is to set base salary and long-and short-term incentive compensation for
our
senior executive officers at the median (50th
percentile) of compensation paid for similar positions by the companies included
in the market surveys. We
set
our target at the median because we believe this target will meet the
requirements of most of the persons we seek to hire and retain in our geographic
area, and because we believe it is fair both to us and to the executives.
Variations
to this objective may, however, occur as dictated by the experience level
of the
individual, internal equity and market factors. We
do not
set a target level for broad-based benefits for our senior executive officers,
but our market survey information indicates that they currently are
approximately at the median.
The
companies
included in the market surveys are a group of utilities and general industry
companies of various sizes in terms of revenue. Approximately half of the
companies included in the most recent market surveys had substantially the
same
levels of annual revenues as we had, while the remainder had revenues not
greater than four times our revenues. Market survey results for each position
are adjusted using regression analysis to account for these differences in
company revenues. To a large extent, the companies included in the survey
results were those that had agreed to participate in market surveys included
in
our compensation consultant’s database.
The
companies included in the market survey we used in connection with setting
base
salaries and short-term incentive compensation for 2006, and the states in
which
they are headquartered are listed below:
Utility
Industry:
AGL
Resources, Inc. (GA); Ameren Corporation (MO); Aquila, Inc. (MO); Black Hills
Corporation (SD); CenterPoint Energy (TX); Cinergy Corp. (OH); Cleco Corporation
(LA); CMS Energy Corporation (MI); Dominion Resources, Inc. (VA); DTE Energy
Company (MI); Duke Energy Corporation (NC); Edison International (CA); El
Paso
Electric Company (TX); FPL Group, Inc. (FL); Great Plains Energy (MO); Nicor
Inc. (IL); NiSource Inc. (IN); Pepco Holdings, Inc. (DC); PNM Resources,
Inc.
(NM); PPL Corporation (PA); Progress Energy, Inc. (NC); Public Service
Enterprise Group (NJ); Sempra Energy (CA); Southern Company (GA); WGL Holdings,
Inc. (DC).
General
Industry:
Alliant
Techsystems Inc. (MN); ALLTEL Corporation (AR); Armstrong World Industries
(PA);
Ball Corporation (CO); Becton Dickinson and Co. (NJ); BorgWarner Inc. (MI);
Brunswick Corporation (IL); C.R. Bard, Inc. (NJ); The Clorox Company (CA);
Cooper Cameron Corp. (TX); Cooper Industries (TX); Ecolab Inc. (MN); FMC
Corporation (PA); Hasbro, Inc. (RI); MeadWestvaco Corporation (VA); Medtronic,
Inc. (MN); Packaging Corp. of America (IL); Praxair, Inc. (CT); The
Sherwin-Williams Co. (OH); Sonoco Products Company (SC); Springs Industries,
Inc. (SC); Steelcase Inc. (MI); Wm. Wrigley Jr. Company (IL).
We
believe the utilities included in our market surveys are an appropriate group
to
use for compensation comparisons because they align well with our sales and
revenues, the nature of our business and workforce, and the talent and skills
required for safe and successful operations. We believe the additional
non-utility companies included in our market surveys are appropriate to include
in our comparisons because they align well with our sales and revenues, and
are
the types of companies that might be expected to seek executives with the
same
general skills and talents as the executives we are trying to attract and
retain
in our geographic area. The companies we use for comparisons may change from
time to time based on the factors discussed above.
To
make
comparisons with the market survey results, we generally divide all of our
senior executive officers into utility and non-utility executive groups -
that
is, executive officers whose responsibilities are primarily related to utility
businesses and require a high degree of technical or industry-specific knowledge
(such as electrical engineering, nuclear engineering or gas pipeline
transmission), and those whose responsibilities are more general and do not
require such specialized knowledge (such as marketing, business and other
corporate support functions). We then attempt to match to the greatest degree
possible our positions with similar positions in the survey results. For
positions that do not fall specifically into the utility or non-utility group,
we may blend the survey results to achieve what we believe is an appropriate
comparison.
We
also
use performance data covering a larger peer group of companies in determining
long-term equity incentive compensation under the SCANA shareholder approved
long-term equity compensation plan, as discussed below under “Long-Term Equity
Compensation Plan.”
Personal
Qualifications
In
addition to considering market survey comparisons, we consider each senior
executive officer’s knowledge, skills, scope of authority and responsibilities,
job performance and tenure with us as a senior executive officer.
Mr.
Timmerman has been our Chief Executive Officer for 10 years, and has been
employed with us in various capacities, including Chief Financial Officer
and
Chief Operating Officer, for over 28 years. Mr. Timmerman started his career
as
a certified public accountant. As our Chief Executive Officer, Mr. Timmerman
has
responsibility for strategic planning, development of our senior executive
officers and oversight of all our operations.
Mr.
Addison was appointed our Senior Vice President and Chief Financial Officer
in
April 2006, prior to which he had served as Vice President-Finance since
2001. As Chief Financial Officer, he is responsible for all of our financial
operations, including accounting, risk management, treasury, investor relations,
shareholder services, taxation and financial planning, as well as our
information technology functions. Mr. Addison is a certified public accountant,
and has been with us for over 15 years.
Mr.
Marsh
was appointed President and Chief Operating Officer of South Carolina Electric
& Gas Company in April 2006, prior to which he had served as Senior
Vice President-Finance and Chief Financial Officer since 1998. As President
of
SCE&G, he is responsible for all of its gas and electric operations, as well
as for all of our facilities and properties management. Mr. Marsh previously
practiced as a certified public accountant and has been with us for over
22
years.
Mr.
Mood
is Senior Vice President and General Counsel. In these positions, he is
responsible for overseeing our legal activities as well as our Legal,
Environmental and Corporate Secretary’s Departments. Mr. Mood has been with us
for two years. Prior to his employment with us, Mr. Mood was in private practice
as a lawyer for 37 years. Mr. Mood has previously served as Interim Dean
of The
University of South Carolina School of Law and as chairman of the South Carolina
Board of Law Examiners, and is a permanent member of the Judicial Conference
of
the United States Court of Appeals for the Fourth Circuit.
Mr.
Bouknight has been with us for two years. He is Senior Vice President - Human
Resources. In this position, he is responsible for all human resources
functions, corporate security, claims and aviation. Mr. Bouknight has over
28
years experience as a human resources professional.
Mr.
Byrne
is Senior Vice President-Generation, Nuclear and Fossil Hydro. In these
positions, he is responsible for overseeing all of our activities related
to
nuclear power, including nuclear plant operations, core analysis, emergency
planning, licensing and nuclear support services. He has been with us for
11
years, and has over 20 years experience in the nuclear industry.
Other
Factors Considered
In
addition to the foregoing information, we consider the fairness
of the
compensation paid to each senior executive officer in relation to what we
pay
our other senior executive officers. The Human Resources Committee also
considers recommendations from our Chairman and Chief Executive Officer in
setting compensation for senior executive officers. We also consider the
senior
executive’s level of ownership of SCANA's common stock in relationship to the
senior executive’s tenure and salary level.
We
review
our compensation program and levels of compensation paid to all of our senior
executive officers, including the Named Executive Officers, annually and
make
adjustments based on the foregoing factors as well as other subjective
factors.
In
2006,
the Human Resources Committee reviewed summaries of compensation components
(“tally sheets”) for all of our senior executive officers, including the Named
Executive Officers. These tally sheets reflected changes in compensation
from
the prior year and affixed dollar amounts to each component of compensation.
The
Committee intends to use such tally sheets in the future to review each
component of the total compensation package, including base salaries, short-and
long-term incentives, severance plans, and insurance, retirement and other
benefits, in determining the total compensation package for each senior
executive officer.
Timing
of Senior Executive Officer Compensation Decisions
Annual
salary reviews and adjustments and short-term and long-term incentive
compensation awards are routinely made in February of each year at the first
regularly scheduled Human Resources Committee and Board meeting. Determinations
also are made at that meeting as to whether to pay out awards under the most
recently completed three-year cycle of long-term equity-based incentive
compensation. Compensation determinations also may be made by the Committee
at
its other quarterly meetings in the case of newly hired executives or promotions
of existing employees that could not be deferred until the February meeting.
We
routinely make our annual and quarterly earnings releases in conjunction
with
the quarterly meetings of our Board.
Base
Salaries
Senior
executive officer base salaries are divided into grade levels based on market
data for similar positions and experience. The Human Resources Committee
believes it is appropriate to set base salaries at a reasonable level that
will
provide executives with a predictable income base on which to structure their
personal budgets. Accordingly, base salaries are targeted at the median
(50th
percentile) of the survey data. The Human Resources Committee reviews base
salaries annually and makes adjustments on the basis of an assessment of
individual performance, relative levels of accountability, prior experience,
breadth and depth of knowledge, changes in market compensation practices
as
reflected in market survey data, and relative compensation levels within
our
company.
With
the
exception of the base salaries of Mr. Addison and Mr. Marsh, the Committee
did
not increase base salaries for the Named Executive Officers in 2006 based
on its
determination that current salaries were appropriate in light of the market
survey data and relative compensation levels within our company. The Committee
increased Mr. Addison’s base salary as a result of his promotion to Senior Vice
President and Chief Financial Officer, and increased Mr. Marsh’s base salary as
a result of his transition to President and Chief Operating Officer of
SCE&G. In making the decisions with respect to the increases in base
salaries for Messrs. Addison and Marsh, and the decision not to increase
base salaries of the other Named Executive Officers, the Committee took into
consideration recommendations of our Chief Executive Officer.
Short-Term
and Long-Term Incentive Compensation
Our
senior executive officer compensation program provides for both short-term
incentive compensation in the form of annual cash incentive compensation,
and
long-term equity-based incentive compensation payable at the end of cycles
which
have historically lasted three years. Both our short-term and long-term
executive incentive compensation plans promote our pay-for-performance
philosophy, as well as our goal of having a meaningful amount of pay "at-risk",
and we believe both plans provide us a competitive advantage in recruiting
and
retaining top quality talent.
We
believe the short-term incentive compensation plan provides our senior executive
officers with an annual stimulus to achieve short-term individual and business
unit or departmental goals and short-term corporate earnings goals that
ultimately help us achieve our long-term corporate goals. We believe the
long-term equity-based incentive compensation counterbalances the emphasis
of
short-term incentive compensation on short-term results by focusing our senior
executive officers on success of our long-term corporate goals; provides
additional incentives for them to remain our employees by ensuring that they
have a continuing stake in the long-term success of the Company; and helps
to
align the interests of senior executive officers with those of shareholders.
Short-Term
Annual Incentive Plan
The
Short-Term Annual Incentive Plan provides financial incentives for performance
in the form of opportunities for annual incentive cash payments. Participants
in
the Short-Term Annual Incentive Plan include not only senior executive
officers, but also approximately 183 additional employees, including other
officers, senior management, division heads and other professionals whose
positions or levels of responsibility make their participation in the plan
appropriate. Our Chief Executive Officer recommends, and the Human Resources
Committee approves, the performance measures, operational goals and other
terms
and conditions of incentive awards for executives, including the Named Executive
Officers.
The
Committee reviews and approves target short-term incentive levels at its
first
regularly scheduled meeting each year based on percentages assigned to each
executive salary grade. Actual short-term incentive awards are based both
on the
Company’s meeting pre-determined financial and business objectives, and on each
senior executive officer’s level of performance as compared to his or her
individual financial and strategic objectives. In assessing accomplishment
of
objectives, the Committee considers the difficulty of achieving each objective,
unforeseen obstacles or favorable circumstances that might have altered the
level of difficulty in achieving the objective, overall importance of the
objective to our long-term and short-term goals, and importance of achieving
the
objective to enhancing shareholder value. Changes in annual target short-term
incentive levels can be made if there are changes in the senior executive
officer’s salary grade level that warrant a target change.
The
plan
allows for an increase or decrease in short-term incentive award payout of
up to
20% of the target award based on an individual’s performance in meeting
individual financial and strategic objectives. The plan also allows for an
increase or decrease in award payout of up to 50% of the target award based
on
the extent to which we achieve our pre-determined financial objectives. However,
cumulative adjustments to target award payouts for all participants may not
increase or decrease overall award levels by more than 50%. Individual awards
may nonetheless be decreased or eliminated if the Human Resources Committee
determines that actual results warrant a lower payout.
For
each
Named Executive Officer, except Mr. Timmerman, the Short-Term Annual Incentive
Plan placed equal emphasis on the following financial and business objectives
for 2006:
| · |
Achieving
earnings per share targets which were set to reflect SCANA’s published
earnings per share growth guidance; and
|
| · |
Achieving
annual business objectives relating to our four critical success
factors:
cost effective operations, profitable growth, excellence in customer
service, and developing our people.
|
For
Mr.
Timmerman, the Short-Term Annual Incentive Plan placed equal emphasis in
2006 on
achieving the earnings per share targets and performance of our senior executive
officers.
The
specific objectives for each senior executive officer are weighted according
to
the extent to which the executive will be responsible for results of the
objectives. The weightings assigned to the business objectives for each Named
Executive Officer for 2006 are shown in the table below:
2006
Weightings Assigned to Each Business Performance Objective
for
Named Executive Officers
|
Objective
|
Mr.
Timmerman
|
Mr.
Marsh
|
Mr.
Addison
|
Mr.
Mood, Jr.
|
Mr.
Bouknight
|
Mr.
Byrne
|
|
Senior
Staff Performance
|
50%
|
|||||
|
Financial
Results
|
50%
|
50%
|
50%
|
50%
|
50%
|
50%
|
|
Cost
Effective Operations
|
20%
|
30%
|
10%
|
40%
|
||
|
Profitable
Growth
|
10%
|
10%
|
10%
|
|||
|
Customer
Service
|
10%
|
10%
|
37.5%
|
10%
|
10%
|
|
|
Developing
our People
|
10%
|
12.5%
|
20%
|
SCANA
did
not achieve earnings per share targets for 2006 and, accordingly, we did
not make any earnings per share-related payouts under the Short-Term Annual
Incentive Plan. However, we achieved our business objectives and our senior
executive officers achieved their individual financial and strategic objectives.
Accordingly, we made payouts to our senior executive officers, including
our
Named Executive Officers, with respect to the business and individual financial
and strategic objectives portions of the plan. As further discussed below
under
the caption “- - Discretionary Bonus Award,” we also made a 20% discretionary
bonus award to each of our senior executives officers, including our Named
Executive Officers as permitted by the plan. The
2006
Short-Term Incentive Plan awards based on our achieving our business
objectives and our Named Executive Officer's achieving their individual
objectives are reflected in the Summary Compensation Table under the column
“Non-Equity Incentive Plan Compensation,” and the discretionary bonus award
under the plan is reflected in the Summary Compensation Table under the column
“Bonus.”
Individual
Financial and Strategic Objectives on which 2006 Short-Term Annual Incentive
Awards were Based
The
individual financial and strategic objectives the Human Resources Committee
considered in determining short-term incentive awards for the Named Executive
Officers were as follows:
Mr.
Timmerman’s award was based on his contributions and his leadership of other
senior executives in achieving our overall corporate strategic plan
objectives. For 2006, our strategic objectives, which were included in
business unit objectives, were leveraging employee and business development;
ensuring the security of our people, assets and operations; optimizing the
use
of our utility assets; effectively addressing new environmental, regulatory
and
legislative issues; and effectively managing fuel and healthcare costs.
Mr.
Addison’s award was based on his successful efforts toward maintaining financial
reporting compliance processes and procedures that meet the requirements
of the
Sarbanes-Oxley Act; his analysis and documentation relating to electric and
gas
regulatory decisions for 2006; his oversight of the successful implementation
of
transition of certain information technology systems and system testing;
and
progress toward development of a plan relating to insurance coverage for
catastrophic property loss risks.
Mr.
Marsh’s award was based on his progress toward developing plans to enhance our
succession strategy; progress toward developing, obtaining approval of, and
preparing for implementation of, a cost effective and responsible environmental
strategy; oversight of efforts to optimize the allocation of natural gas
assets
and implementation of the transition to open access; identification and tracking
of compliance with existing and emerging regulations; and effectiveness in
managing the operation and maintenance and capital budgets.
Mr.
Mood’s award was based on his effective oversight of implementation of annual
internal reporting and assessments relating to environmental issues; fostering
collaborative relationships between our legal department and our business
units;
effective oversight of training relating to Federal Energy Regulatory Commission
regulations; and effective oversight of the legal, environmental, and corporate
secretary departments’ staffing and management.
Mr.
Bouknight’s award was based on his successful oversight of the development and
implementation of a succession and leadership development program; progress
toward improved interaction between the Human Resources department and its
constituencies; successful oversight of completion of a company-wide Human
Resources department website; and successful oversight of programs focused
on
employee health and wellness.
Mr.
Byrne’s award was based on his oversight of our achieving a system availability
factor beyond targeted levels for our fossil hydro operations; the fact that
our
fossil hydro operations demonstrated environmental responsibility; oversight
of
successful implementation of certain system modifications during refueling
at
our nuclear plant; oversight of a very successful refueling outage; and
oversight of progress toward licensing, site selection, vendor selection
and
project development agreement for a potential new nuclear plant.
Discretionary
Bonus Award
The
20%
discretionary bonus awards were recommended to the Human Resources Committee
by
our Chief Executive Officer, and both the Human Resources Committee and the
Board approved the discretionary payout. The bases for the discretionary
portion of the award are as follows:
| · |
Two
primary factors that held down financial performance (mild weather
and
loss of industrial customers) were not within the control of our
employees;
|
| · |
Our
management team has made tremendous progress this year dealing with
long-term strategic issues, such as planning for future expansion
of
generation, coping with pending environmental challenges, and dealing
with
a host of federal regulatory changes that are both complex and often
not
well defined; and
|
| · |
There
were a number of exceptional short term accomplishments in the past
year,
including having three of our coal fired plants rated among the 20
most
efficient plants in the United States.
|
We
believe this discretionary payment to our short-term bonus plan participants
is
well-justified and necessary to reward and retain our critical human
resources.
Long-Term
Equity Compensation Plan
The
potential value of long-term equity-based incentive opportunities comprises
a
significant portion of the total compensation package for senior executive
officers and key employees. The Human Resources Committee believes this approach
to total compensation provides the appropriate long-range focus for senior
executive officers and other key employees who are charged with responsibility
for managing the Company and achieving success for shareholders because it
links the amount of their compensation to our business and financial
performance.
A
portion
of each senior executive officer's potential compensation consists of awards
under the Long-Term Equity Compensation Plan. The types of long-term
equity-based compensation the Human Resources Committee may award under the
plan
include incentive and nonqualified stock options, stock appreciation rights
(either alone or in tandem with a related stock option), restricted stock,
performance units and performance shares. In recent years, the only long-term
equity-based awards have been in the form of performance shares and performance
units. These long-term equity-based awards are granted subject to satisfaction
of specific performance goals. For the 2006-2008 performance period, awards
under the Long-Term Equity Compensation Plan consisted solely of performance
shares. We have not awarded stock options since 2002 and have no plans to
do so
in the foreseeable future.
Payouts
of awards under the Long-Term Equity Compensation Plan may be made in cash
or
SCANA common stock at our discretion, but are most frequently made in cash.
We
believe awards of performance units and performance shares align the interests
of our executives with those of shareholders because the value of such awards
is
tied to our achieving financial and business goals that would be expected
to
affect the value of SCANA's common stock.
Performance
Share Awards
For
the
2005-2007 and 2006-2008 plan cycles, performance share awards to senior
executive officers under the Long-Term Equity Compensation Plan were based
on
(1) SCANA's Total Shareholder Return ("TSR") relative to the TSR of a group
of
peer companies over the three-year periods and (2) a three-year average growth
in earnings component based on SCANA's earnings per share under generally
accepted accounting principles, with adjustments to be made to account for
the
cumulative effects of any mandated changes in accounting principles and the
effects of any sales of certain investments or impairment charges related
to
certain investments (we refer to this component as growth in “EPS from ongoing
operations”).
TSR
over
the three-year periods is equal to the change in SCANA's common stock price,
plus cash dividends paid on SCANA's common stock during the period, divided
by
SCANA's common stock price as of the beginning of the period.
Performance
share awards place a portion of executive compensation at risk because
executives are compensated pursuant to the awards only when the objectives
for
TSR and earnings growth are met. Additionally, comparing TSR to the TSR of
a group of other companies reflects our recognition that investors could
have
invested their funds in other entities, and measures how well we performed
over
time when compared to others in the group.
Creating
a new three-year cycle each year provides an opportunity to adjust the target,
threshold and maximum award levels based on historical performance, and provides
an ongoing long-term incentive to senior executive officers. Payouts
under the 2005-2007 and 2006-2008 cycles will be based upon the extent to
which SCANA meets its performance goals for the entire three-year
periods.
Beginning
with the 2007-2009 plan cycle, however, the Long-Term Equity Compensation
Plan
provides for performance measurement and award determination on an annual
basis (rather than the above described three-year measurement and
determination), with payment of awards being deferred until after the end
of the
three-year performance cycle. Accordingly,
payouts under the 2007-2009 plan cycle will be earned for each year that
performance goals are met during the three-year cycle, though payments will
be
deferred until the end of the cycle and will be contingent upon the
participant’s still being employed by us at the end of the cycle, subject to
certain exceptions in the event of retirement, death or disability.
Additionally, the payment of the EPS growth component of the 2007-2009 plan
cycle awards will be based on growth in “GAAP-adjusted net earnings per share
from operations” as that term is used in SCANA’s periodic reports and external
communications. GAAP-adjusted net earnings per share from operations may
reflect
different or additional adjustments than are or would have been reflected
in the
determination of EPS from ongoing operations in prior plan cycles. We believe
that these changes for the 2007-2009 cycle will increase the effectiveness
of the plan in encouraging executive retention by minimizing the impact of
extraordinarily strong or poor single-year performance on award payouts.
The
other
performance criteria adopted by the Board on recommendation of the Human
Resources Committee for the 2007-2009 plan cycle do not differ materially
from the 2006-2008 plan cycle.
2006
Long-Term Incentive Plan Awards
In
2006,
we made performance share awards to each of the Named Executive Officers.
The
awards have a three-year cycle ending in 2008 and are payable based on SCANA
levels of performance against pre-determined measures of TSR and average
growth
in EPS from ongoing operations over the three-year plan cycle. Information
about
the performance criteria for the 2006-2008 cycle is set forth below. Information
about the number of performance shares awarded for the 2006-2008 cycle is
provided in the “2006 Grants of Plan-Based Awards” table.
Sixty
percent of the 2006 target performance share awards are based on SCANA's
TSR
over the three-year plan cycle compared with the peer group of utilities
set
forth below:
Allegheny
Energy, Inc.; Allete Inc.; Alliant Energy Corporation; Ameren Corporation;
Avista Corporation; Cinergy Corp.; Cleco Corporation; CMS Energy Corporation;
Consolidated Edison, Inc.; Constellation Energy Group, Inc.; Dominion Resources,
Inc.; DPL, Inc.; DTE Energy Company; Duquesne Light Holdings, Inc.; Edison
International; Energy East Corporation; Entergy Corporation; FirstEnergy
Corp.;
FPL Group, Inc.; Great Plains Energy, Inc.; Hawaiian Electric Industries,
Inc.;
IDACORP, Inc.; NiSource Inc.; Northeast Utilities; NorthWestern Corporation;
NSTAR; OGE Energy Corp.; Pepco Holdings, Inc.; Pinnacle West Capital
Corporation; PNM Resources, Inc.; PPL Corporation; Progress Energy, Inc.;
Public
Service Enterprise Group, Inc.; Puget Energy, Inc.; Sierra Pacific Resources;
Southern Company; TECO Energy, Inc.; UIL Holdings Corporation; UniSource
Energy
Corporation; Vectren Corporation; Westar Energy, Inc.; Wisconsin Energy
Corporation; WPS Resources Corporation.
The
number of utilities included in the peer group used for TSR comparisons is
larger than the number included in the market survey utility peer group we
use
for purposes of setting base salary and short-term incentive compensation
because information about TSR is publicly available for a larger number of
utilities. We include only utilities in the TSR peer group because we have
assumed that shareholders would measure SCANA's performance against performance
of other utilities in which they might have invested.
Payouts
based on the TSR component of the plan are scaled according to SCANA's ranking
against the peer group. No payout is earned if performance is less than the
33rd percentile. Senior executive officers earn threshold payouts (equal
to 50%
of target award) if SCANA ranks at the 33rd percentile in relation to the
peer group's three-year TSR performance. Target payouts (equal to 100% of
target
award) occur if SCANA ranks at the 50th percentile in relation to the peer
group's three-year TSR performance. Maximum payouts (equal to 150% of target
award) result if performance ranks at or above the 75th percentile in
relation to the peer group's three-year TSR performance. Payouts are scaled
between 50% and 150% based on the actual percentile achieved. No payouts
may
exceed 150% of the target award. Threshold, target and maximum payouts at
the
33rd,
50th
and
75th
percentiles were used because these match generally the levels used by the
companies in the market survey data.
Forty
percent of the 2006 performance share awards were based on meeting SCANA's
projections for three-year average growth in EPS from ongoing operations.
Payouts for target performance share awards granted in 2006 for the 2006-2008
performance period will be made if three-year average growth in EPS from
ongoing
operations equals 3.7%. Executives would earn threshold payouts (equal to
50% of target award) at 1.7% average growth, target payouts (equal to 100%
of
target award) at 3.7% average growth, and maximum payouts (equal to 150%
of
target award) at or above 5.7% average growth. Payouts are scaled between
50%
and 150% based on the actual growth in EPS from ongoing operations achieved.
No
payouts will occur if average growth in EPS from ongoing operations over
the
three-year period is less than 1.7% and no payouts will exceed 150% of target
award.
Performance
share awards are denominated in shares of SCANA's common stock. The number
of
performance shares into which awards are denominated at grant is calculated
by
multiplying the Named Executive Officer’s base salary by a target percentage,
and dividing the product by the discounted opening stock price on the date
of
grant. The target percentage is derived from market survey data of the peer
companies listed above under “Factors Considered in Setting Senior Executive
Officer Compensation - - Use of Market Surveys and Peer Group Data.” The
discounted stock price is provided to us by our compensation consultants.
Performance share awards may be paid in stock or cash or a combination of
stock
and cash at our discretion. Based on past practices, we currently anticipate
that payouts will be in cash. Payouts are based on the closing market price
of
SCANA's common stock on the last date of the plan cycle.
The
allocation of 60% of awards to three-year TSR and 40% to EPS from ongoing
operations was made to weight the external performance measure slightly higher
than the internal performance measure.
2006
Payouts Under Performance Share Awards and Performance Unit Awards Granted
in
2004
Performance
Share Awards
Payouts
for target performance share awards granted in 2004 for the 2004-2006
performance period were based on achieving TSR in the top two-thirds
of the TSR for the Long-Term Equity Compensation Plan peer group over the
three-year period. Executives would earn threshold payouts (equal to 50%
of
target award) if SCANA ranked at the 33rd percentile in relation to the peer
group's three-year TSR performance. Target payouts (equal to 100% of target
award) would be earned if SCANA ranked at the 50th percentile in relation
to the
peer group's three-year TSR performance. Maximum payouts (equal to 150% of
target award) would be earned if SCANA ranked at or above the 75th percentile
in
relation to the peer group's three-year TSR performance. Payouts were scaled
between 50% and 150% based on the actual percentile achieved. No payouts
would
be earned if TSR were at less than the 33rd percentile and no payouts would
exceed 150% of the target award.
For
the
three-year performance period 2004-2006, TSR was below the 33rd
percentile of the peer group's TSR which resulted in no payouts for the period.
Performance
Unit Awards
Payouts
for performance unit awards granted in 2004 for the 2004-2006 performance
period
were based on meeting projections for three-year average growth in EPS
from ongoing operations. Senior executive officers would earn threshold payouts
(equal to 50% of target award) at 2% average growth, target payouts (equal
to
100% of target award) at 4% average growth and maximum payouts (equal to
150% of
target award) at or above 6% average growth. Payouts were scaled between
50% and
150% based on the actual growth in EPS from ongoing operations achieved.
No
payouts would occur if average growth in EPS from ongoing operations over
the
period was less than 2% and no payouts would exceed 150% of target award.
These
threshold, target and maximum payout levels were consistent with the earnings
growth guidance provided publicly by management at the time of the grants.
For
the
three-year performance period 2004-2006, average growth in EPS from ongoing
operations fell below the 2% threshold which resulted in no payouts for the
period.
Retirement
and Other Benefit Plans
SCANA
currently sponsors the following retirement benefit plans which are available
to
eligible senior officers of SCE&G (as such, these plans may be referred to
herein as "our" plans):
| · |
a
tax qualified defined benefit retirement plan (the “Retirement Plan”),
|
| · |
a
non-tax qualified defined benefit Supplemental Executive Retirement
Plan
(the “SERP”) for our senior executive officers,
|
| · |
a
tax qualified defined contribution plan (the “401(k) Plan”),
and
|
| · |
a
non-tax qualified defined contribution Executive Deferred Compensation
Plan (the “EDCP”) for our senior executive
officers.
|
All
employees who have met eligibility requirements may participate in the
Retirement Plan and the 401(k) Plan.
The
SERP
and the EDCP plans are designed to provide a benefit to senior executive
officers who participate in the Retirement Plan or 401(k) Plan (our
tax-qualified retirement plans) and whose participation in those tax-qualified
plans is otherwise limited by government regulation. The SERP and EDCP
participants are provided with the benefits to which they would have been
entitled under the Retirement Plan or 401(k) Plan had their participation
not
been limited. At present, certain executive officers including the Named
Executive Officers are participants in the SERP and/or EDCP.
The SERP
and the EDCP are described under the caption “Potential Payments Upon
Termination or Change in Control - Retirement Benefits.” We provide the SERP and
EDCP benefits because they allow our senior executive officers the opportunity
to defer the same percentage of their compensation as other employees. We
also
believe, based on market survey data, that these plans are necessary to make
our
senior executive officer retirement benefits competitive.
We
also
provide other benefits such as medical, dental, life and disability insurance,
which are available to all of our employees. In addition, we provide certain
of
our executive officers with additional long-term disability insurance and
term
life insurance.
Termination,
Severance and Change in Control Arrangements
We
have
entered into arrangements with certain of our senior executive officers,
including our Named Executive Officers, that provide for payments to them
in the
event of a change in control of SCANA or SCE&G. These arrangements,
including the triggering events for payments and possible payment amounts,
are
described under the caption “Potential Payments Upon Termination or Change in
Control.” These arrangements are not uncommon for executives at the level of our
Named Executive Officers including executives of the companies included in
our
compensation market survey information, and are generally expected by those
holding such positions. We believe these arrangements are an important factor
in
attracting and retaining our senior executive officers by assuring them
financial and employment status protections in the event control of SCANA
or
SCE&G changes. We believe such assurances of financial and employment
protections help free executives from personal concerns over their futures,
and,
thereby, can help to align their interests more closely with those of
shareholders in negotiating transactions that could result in a change in
control.
Perquisites
We
provide a number of perquisites to senior executive officers as summarized
below.
Company
Aircraft
SCANA
maintains two turboprop aircraft for the use of officers and managers in
their
travels to various operations throughout our service areas, as well as to
meet
with regulatory bodies, industry groups and financial groups, principally
in
Washington, D. C. and New York, New York. Our senior executive officers may
use
the aircraft for business purposes on a non-exclusive basis. The aircraft
may
also be used from time to time to transport directors to and from meetings
and
committee meetings of the Board of Directors. Spouses or close family members
of
directors and senior executive officers occasionally accompany a director
or
senior executive officer on the aircraft when the director or executive officer
is flying for our business purposes. On very rare occasions, a senior executive
officer may use our aircraft for personal use that is not in connection with
a
business purpose. We impute income to the executive for certain expenses
related
to such use.
For
purposes of determining total 2006 compensation, we valued the aggregate
incremental cost of the personal use of the aircraft using a method that
takes
into account the variable expenses associated with operating the aircraft,
which
variable expenses are only incurred if the planes are flying. Items included
in
our aggregate incremental cost are as follows: aircraft fuel and oil expenses
per hour of flight; crew salaries; maintenance, parts and external labor
(inspections and repairs) per hour of flight; aircraft accrual expenses per
hour
of flight; landing/parking/flight planning services expenses; crew travel
expenses; and supplies and catering.
Medical
Examinations
We
provide each of our senior executive officers the opportunity to have a
comprehensive annual medical examination from Duke University, the Medical
University of South Carolina or the physician of his or her choice. We believe
this examination helps encourage health-conscious senior executive officers,
and
helps us plan for any health related retirements or resignations.
Security
Systems
We
offer
free installation and provide monitoring of home security systems for our
senior
executive officers. Because we operate a nuclear facility and provide essential
services to the public, we believe we have a duty to help assure uninterrupted
and safe operations by protecting the safety and security of our senior
executive officers. We provide such installation and monitoring at multiple
homes for some senior executive officers.
Other
Perquisites
We
provide a taxable allowance to our senior executive officers for financial
counseling services, including tax preparation and estate planning services.
We
value this benefit based on the actual charges. We also pay the initiation
fees
and monthly dues for one dining club membership for each senior executive
officer for business use. We allow spouses to accompany directors and senior
executive officers to our quarterly Board meetings because we believe social
gatherings of directors and senior executive officers in connection with
these
meetings increases collegiality. Some of our meetings are at resort locations
where resort amenities may be provided.
Accounting
and Tax Treatments of Compensation
Deductibility
of Executive Compensation
Section 162(m)
of the Internal Revenue Code establishes a limit on the deductibility of
annual
compensation in excess of $1,000,000 for certain senior executive officers,
including the Named Executive Officers. Certain performance-based compensation
approved by shareholders is not subject to the deduction limit. The
Long-Term Equity Compensation Plan is qualified so that most performance-based
awards under that plan constitute compensation that is not subject to
Section 162(m). The Short-Term Incentive Plan does not meet 162(m)
deductibility requirements. To maintain flexibility in compensating senior
executive officers in a manner designed to promote various corporate goals,
the
Human Resources Committee has not adopted a policy that all compensation
must be
deductible. Since Mr. Timmerman’s salary is above the $1,000,000
threshold, we may not deduct a portion of his compensation. The Human
Resources Committee considered these tax and accounting effects in connection
with its deliberations on senior executive compensation.
Nonqualified
Deferred Compensation
On
January 1, 2005, the Internal Revenue Code was amended to include a new Section
409A, which would impose interest and penalties on receipt of certain types
of
deferred compensation payments. Deferred compensation plans are required
to be
amended to comply with the requirements of Section 409A, if necessary, by
the
end of 2007 to avoid imposition of such interest and penalties. In the meantime,
the plans must operate in good faith compliance with Section 409A, and we
believe our deferred compensation plans meet this requirement. We have
determined that amendments will be required to the Supplemental Executive
Retirement Plan, the Executive Deferred Compensation Plan, the Key Executive
Severance Benefits Plan and the Supplementary Key Executive Severance Benefits
Plan to cause these plans to comply with Section 409A. The Human Resources
Committee expects to address these amendments in 2007.
Accounting
for Stock Based Compensation
Beginning
January 1, 2006, we began accounting for stock based compensation in accordance
with the requirements of FASB Statement 123(R).
Compensation
for 2007
On
February 15, 2007, the Board, on the recommendation of the Human Resources
Committee, adopted criteria for performance awards for the 2007 - 2009
performance cycle under the Long-Term Equity Compensation Plan. These criteria
are discussed under “- - Long-Term Equity Compensation Plan - - Performance
Share Awards.”
On
the
same day, upon recommendation of the Human Resources Committee, the Board
approved base salaries for our Named Executive Officers and criteria for
performance awards under our Short-Term Annual Incentive Plan for the year
2007.
Such base salaries and performance award criteria do not differ materially
from
year 2006 levels.
As
noted
above, in 2007, the Human Resources Committee expects to make amendments
to our
deferred compensation plans as necessary to address issues raised by Internal
Revenue Code Section 409A.
Financial
Restatement
Although
we have never experienced such a situation, our Board of Directors’ policy is to
consider on
a
case-by-case basis a retroactive adjustment to any cash or equity-based
incentive compensation paid to our senior executive officers where payment
was
conditioned on achievement of certain financial results that were subsequently
restated or otherwise adjusted in a manner that would reduce the size of
a prior
award or payment.
Security
Ownership Guidelines for Executive Officers
We
do not
currently have any equity or other security ownership guidelines or requirements
for executive officers (specifying applicable amounts and forms of ownership),
or any policies regarding hedging the economic risk of such ownership. However,
all of our senior executive officers have a significant amount of their 401(k)
plan accounts invested in SCANA stock.
Compensation
Committee Interlocks and Insider Participation
During
2006, decisions on various elements of executive compensation were made
by the
Human Resources Committee. No officer, employee or former officer or any
related
person of SCANA or any of its subsidiaries served as a member of the Human
Resources Committee.
The
directors who served on the Human Resources Committee during 2006
were:
Mr.
G. Smedes York, Chairman
Mr.
Bill L. Amick*
Mr.
James A. Bennett
Mr.
William C. Burkhardt
Mrs.
Sharon A. Decker
Mr.
D. Maybank Hagood
Ms.
Lynne M. Miller
Mr.
Maceo K. Sloan
*Mr.
Amick served on the Committee until August 2, 2006.
Compensation
Committee Report
The
Human
Resources Committee has reviewed and discussed with management the “Compensation
Discussion and Analysis” included herein. Based on that review and discussion,
the Human Resources Committee recommended to our Board of Directors that
the
“Compensation Discussion and Analysis” be included in our Annual Report on Form
10-K for the year ended December 31, 2006 for filing with the Securities
and
Exchange Commission.
Mr.
G. Smedes York (Chairman)
Mr.
James A. Bennett
Mr.
William C. Burkhardt
Mrs.
Sharon A. Decker
Mr.
D. Maybank Hagood
Ms.
Lynne M. Miller
Mr.
Maceo K. Sloan
SUMMARY
COMPENSATION TABLE
The
following table summarizes information about compensation paid or accrued
during
2006 to our Chief Executive Officer, our Chief Financial Officer and former
Chief Financial Officer and our three next most highly compensated executive
officers. (As noted in the Compensation Discussion and Analysis, we refer
to
these persons as our Named Executive Officers.)
|
Name
and
Principal
Position
|
Year
|
Salary
($)
|
Bonus
($)(1)
|
Stock
Awards
($)(2)
|
Option
Awards
($)
|
Non-
Equity
Incentive Plan Compen-sation
($)(3)
|
Change
in Pension Value and Nonquali-
fied
Deferred
Compensa-tion
Earnings
($)(4)
|
All
Other
Compen-sation
($)(5)
|
Total
($)
|
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
(f)
|
(g)
|
(h)
|
(i)
|
(j)
|
|
W.B.
Timmerman, Chief Executive Officer
|
2006
|
$1,002,700
|
$170,459
|
$-1,398,181
|
0
|
$426,148
|
$274,724
|
$73,629
|
$549,479
|
|
J.
E. Addison, Chief Financial Officer(6)
|
2006
|
$278,990
|
$27,916
|
$-156,699
|
0
|
$69,789
|
$21,981
|
$30,091
|
$272,068
|
|
K.
B.
Marsh,
President and Chief Operating Officer (7)
|
2006
|
$516,183
|
$66,916
|
$-478,476
|
0
|
$167,290
|
$59,934
|
$63,816
|
$395,663
|
|
F.
P. Mood, Jr., Senior Vice President and General Counsel
|
2006
|
$350,000
|
$35,000
|
$27,075(8)
|
0
|
$87,500
|
$59,582
|
$41,051
|
$600,208
|
|
J.
C. Bouknight, Senior Vice President
|
2006
|
$290,000
|
$29,000
|
$-160,656
|
0
|
$72,500
|
$38,872
|
$32,901
|
$302,617
|
|
S.
A.
Byrne,
Senior Vice President
|
2006
|
$400,400
|
$48,048
|
$-346,911
|
0
|
$120,120
|
$40,226
|
$45,550
|
$307,433
|
(1) Discretionary
bonus awards as permitted under the Short-Term Annual Incentive Plan, which
are discussed in further detail under “- - Compensation Discussion and Analysis
- - Short-Term Annual Incentive Plan - - Discretionary Bonus Award.”
(2) The
information in this column relates to performance share awards (liability
awards) under the Long-Term Equity Compensation Plan. This plan is discussed
under "- - Compensation Discussion and Analysis - Long-Term Equity
Compensation Plan - 2006
Long-Term Incentive Plan Awards."
The
assumptions made in valuation of stock awards are set forth in Note 3
under
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCE&G in Part
II above.
As
explained below, the amounts in this column do not represent deductions from
compensation actually paid to our Named Executive Officers, or repayments
by
them of previously awarded compensation. Rather, this column reflects the
aggregate amounts recorded as (negative) compensation expense in the income
statement and amounts which were (credited to) capitalized costs in the
financial statements for the year ended December 31, 2006, for all three
plan
performance cycles which were in operation during the year. As such, the
amounts reported include not only compensation cost recognized with respect
to
awards granted in
2006 for
the 2006-2008 plan cycle,
but also
reductions
of accruals in prior years of compensation
cost
related
to
awards
granted in 2004
for
the 2004-2006 plan cycle and in 2005 for
the
2005-2007 plan cycle.
During
2006, SCANA's EPS from ongoing operations did not grow, and its
TSR performance lagged the peer group. As
such,
awards for the 2004-2006 plan cycle, for which significant amounts had been
accrued in prior years, fell below performance threshold payout
levels,
with
requisite reductions of prior accruals being recorded in 2006. Similarly,
prior
accruals related to the 2005-2007 plan cycle were reduced in 2006 based on
this
decline in relative TSR and lower earnings growth performance. These reductions
of prior compensation cost accruals were only partially offset by accruals
related to the 2006-2008 plan cycle, which accruals were also limited by
the
2006 TSR and EPS from ongoing operations performance.
(3)
Payouts
under the Short-Term Annual Incentive Plan, which is discussed in further
detail under "- - Compensation Discussion and Analysis - Short-Term Annual
Incentive Plan."
(4)
The
aggregate change in the actuarial present value of each Named Executive
Officer's accumulated benefits under SCANA's Retirement Plan and Supplemental
Executive Retirement Plan from December 31, 2005 to December 31, 2006,
determined using interest rate and mortality rate assumptions consistent
with
those used in our financial statements. These plans are discussed under "-
-
Compensation Discussion and Analysis - Retirement and Other Benefit
Plans."
(5)
All
other
compensation paid to each Named Executive Officer, including company
contributions to the 401(k) Plan and the Executive Deferred Compensation
Plan,
tax reimbursements with respect to perquisites or other personal benefits,
and
life insurance premiums on policies owned by Named Executive Officers. For
2006, contributions to defined contribution plans were as follows: Mr. Timmerman
- $66,420; Mr. Addison - $26,306; Mr. Marsh - $60,044; Mr. Mood - $36,750;
Mr.
Bouknight - $29,145; Mr. Byrne - $42,042. For 2006, tax reimbursements
with respect to perquisites or other personal benefits were as follows:
Mr. Timmerman - $1,463; Mr. Addison - $716; Mr. Marsh - $133; Mr. Mood -
$205;
Mr. Bouknight - $527; and Mr. Byrne - $442. Neither life insurance
premiums on policies owned by the Named Executive Officers nor perquisites
exceeded $10,000 for any Named Executive Officer.
(6)
Mr.
Addison was appointed as our Chief Financial Officer in April,
2006.
(7)
Mr.
Marsh
served as our Chief Financial Officer until April, 2006, at which time he
was
appointed as the President and Chief Operating Officer of
SCE&G.
(8)
Mr.
Mood
did not participate in the 2004-2006 or 2005-2007 cycles of the Long-Term
Equity Compensation Plan and, therefore, no accruals under these cycles had
to
be reversed with respect to him. The amount shown for Mr. Mood represents
the
accruals related to the award under the 2006-2008 cycle as discussed under
footnote 2 above.
2006
GRANTS OF PLAN-BASED AWARDS
The
following table sets forth each grant of an award made to a Named Executive
Officer under our compensation plans during 2006.
|
Name
|
Grant
Date
|
Estimated
Possible Payouts Under Non-Equity Incentive Plan Awards(1)
|
Estimated
Future Payouts Under Equity Incentive Plan Awards(2)
|
All
Other Stock Awards:Number of Shares of Stock or Units
(#)
|
All
Other Option Awards: Number of Securi-ties Under-lying
Options
(#)
|
Exer-cise
or Base Price of Option Awards
($/Sh)
|
Grant
Date Fair Value of
Stock
and Option A-wards
|
||||
|
Thresh-old
($)
|
Target
($)
|
Maximum
($)
|
Thresh-old
(#)
|
Target
(#)
|
Maxi-mum
(#)
|
||||||
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
(f)
|
(g)
|
(h)
|
(i)
|
(j)
|
(k)
|
(l)
|
|
W.
B. Timmerman
|
2-16-06
|
$426,148
|
$852,295
|
$1,278,443
|
35,044
|
70,088
|
105,132
|
||||
|
J.
E. Addison
|
2-16-06
|
$69,789
|
$139,578
|
$209,367
|
4,356
|
8,711
|
13,067
|
||||
|
K.
B.
Marsh
|
2-16-06
|
$167,290
|
$334,580
|
$501,870
|
12,397
|
24,794
|
37,191
|
||||
|
F.
P.
Mood,
Jr.
|
2-16-06
|
$87,500
|
$175,000
|
$262,500
|
5,811
|
11,621
|
17,432
|
||||
|
J.
C. Bouknight
|
2-16-06
|
$72,500
|
$145,000
|
$217,500
|
4,308
|
8,615
|
12,923
|
||||
|
S.
A.
Byrne
|
2-16-06
|
$120,120
|
$240,240
|
$360,360
|
7,697
|
15,393
|
23,090
|
||||
(1)
The
amounts in columns (c), (d) and (e) represent the threshold, target and maximum
awards that could have been paid under the Short-Term Annual Incentive Plan
if performance criteria were met. Performance criteria were met only at the
threshold level, and therefore, as reflected in the Summary Compensation
Table,
the amounts paid were those shown in column (c). A discussion of
the Short-Term Annual Incentive Plan is included under “- - Compensation
Discussion and Analysis - Short-Term Annual Incentive Plan.” See also, “- -
Compensation Discussion and Analysis - - Short-Term Annual Incentive Plan
- -
Discretionary Bonus Award” for a discussion of the discretionary bonus paid
under this plan.
(2)
Represents
potential future payouts of the 2006-2008 cycle of performance share awards
under the Long-Term Equity Compensation Plan. Payout of performance share
awards
will be dictated by SCANA's performance against pre-determined measures of
TSR and growth in EPS from ongoing operations over the three-year plan cycle.
A
discussion of the components of the performance share awards is included
under
"- - Compensation Discussion and Analysis - - Long-Term Equity Compensation
Plan
- - Performance Share Awards."
OUTSTANDING
EQUITY AWARDS AT 2006 FISCAL YEAR-END
The
following table sets forth certain information regarding unexercised options
and
equity incentive plan awards for each Named Executive Officer outstanding
as of
December 31, 2006.
|
Option
Awards
|
Stock
Awards
|
||||||||
|
Name
|
Number
of
Securities
Underlying
Unexercised
Options
(#)
Exer-cisable(1)
|
Number
of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
|
Equity
Incentive Plan
Awards:
Number
of
Securities
Underlying Unexercised Unearned Options
(#)
|
Option
Exercise Price
($)
|
Option
Expiration
Date
|
Number
of Shares or Units of Stock That Have
Not
Vested
(#)
|
Market
Value of Shares or Units of Stock That Have Not Vested
($)
|
Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units
or
Other
Rights
That
Have
Not
Vested
(#)(2)(4)
|
Equity
Incentive
Plan
Awards:
Market or Payout
Value
of
Unearned
Shares,
Units
or
Other
Rights
That
Have
Not
Vested
($)(3)
(4)
|
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
(f)
|
(g)
|
(h)
|
(i)
|
(j)
|
|
W.
B. Timmerman
|
123,067
|
$27.52
|
02/21/2012
|
99,153
|
$4,027,595
|
||||
|
J.
E.
Addison
|
10,157
|
$412,577
|
|||||||
|
K.
B.
Marsh
|
32,968
|
$1,339,160
|
|||||||
|
F.
P.
Mood,
Jr.
|
14,692
|
$596,789
|
|||||||
|
J.
C. Bouknight
|
11,102
|
$450,963
|
|||||||
|
S.
A.
Byrne
|
21,492
|
|
$27.52
|
02/21/2012
|
19,276
|
$782,991
|
|||
(1)
The
vesting date of Mr. Byrne’s options was February 21, 2005. All other options
were exercised after December 31, 2006.
(2)
Assuming
the performance criteria are met, the vesting dates of these awards would
be as
follows: Mr. Timmerman - 50,091 shares would vest on December 31, 2007 and
49,062 shares would vest on December 31, 2008; Mr. Addison - 4,059 shares
would
vest on December 31, 2007 and 6,098 shares would vest on December 31, 2008;
Mr.
Marsh - 15,612 shares would vest on December 31, 2007 and 17,356 shares would
vest on December 31, 2008; Mr. Mood - 6,557 shares would vest on December
31,
2007 and 8,135 shares would vest on December 31, 2008; Mr. Bouknight - 5,071
shares would vest on December 31, 2007 and 6,031 shares would vest on December
31, 2008; Mr. Byrne - 8,501 shares would vest on December 31, 2007 and 10,775
shares would vest on December 31, 2008.
(3)
The
market value of these awards is based on the closing market price of SCANA
common stock on the New York Stock Exchange on December 29, 2006 of
$40.62.
(4)
For
the
2004-2006 plan cycle, no shares vested or were earned because performance
criteria were not met. For the 2005-2007 cycle, performance shares tracking
against SCANA's total shareholder return (60% of target shares) are projected
to
result in zero payout. Therefore, the number of shares and payout value
shown in columns (i) and (j) are based on the threshold performance measure
for
the TSR portion of the shares. Performance shares tracking against SCANA's
growth in EPS from ongoing operations (40% of target shares) for the
2005-2007 cycle are projected to result in a payout between threshold and
target. Therefore, the number of shares and payout value shown in columns
(i) and (j) are based on the target performance measure for the growth in
EPS
from ongoing operations portion of the shares. For the 2006-2008 cycle,
performance shares tracking against SCANA's total shareholder return (60%
of
target shares) are projected to result in zero payout. Therefore, the
number of shares and payout value shown in columns (i) and (j) are based
on the
threshold performance measure for the TSR portion of the shares. Performance
shares tracking against SCANA's growth in EPS from ongoing operations (40%
of
target shares) for the 2006-2008 cycle are projected to result in a payout
between threshold and target. Therefore, the number of shares and payout
value shown in columns (i) and (j) are based on the target performance measure
for the growth in EPS from ongoing operations portion of the
shares.
2006
OPTION EXERCISES AND STOCK VESTED
The
following table sets forth information about exercises of stock options for
each
Named Executive Officer during 2006. No stock awards vested in
2006.
|
Option
Awards
|
Stock
Awards
|
||||||||||||
|
Name
|
Number
of
Shares
Acquired
on
Exercise
(#)
|
Value
Realized
on
Exercise
($)
|
Number
of
Shares
Acquired
on
Vesting
(#)
|
Value
Realized
on
Vesting
($)
|
|||||||||
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
|||||||||
|
W.
B.
Timmerman
|
|||||||||||||
|
J.
E.
Addison
|
|||||||||||||
|
K.
B.
Marsh
|
25,939
|
$
|
297,779
|
||||||||||
|
F.
P.
Mood,
Jr.
|
|||||||||||||
|
J.
C.
Bouknight
|
|||||||||||||
|
S.
A.
Byrne
|
27,938
|
$
|
317,369
|
||||||||||
PENSION
BENEFITS
The
following table sets forth certain information relating to the Retirement
Plan
and Supplemental Executive Retirement Plan (SERP).
|
Name
|
Plan
Name
|
Number
of
Years
Credited
Service
(#)(1)
|
Present
Value
of Accumulated Benefit
($)(1)
(2)
|
Payments
During
Last
Fiscal
Year
($)
|
|||||||||
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
|||||||||
|
W.
B.
Timmerman
|
SCANA
Ret. Plan
SCANA
SERP
|
28
28
|
$
$
|
792,631
2,090,423
|
0
0
|
||||||||
|
J.
E.
Addison
|
SCANA
Ret. Plan
SCANA
SERP
|
15
15
|
$
$
|
128,406
68,597
|
0
0
|
||||||||
|
K.
B.
Marsh
|
SCANA
Ret. Plan
SCANA
SERP
|
22
22
|
$
$
|
423,655
369,986
|
0
0
|
||||||||
|
F.
P.
Mood,
Jr.
|
SCANA
Ret. Plan
SCANA
SERP
|
2
2
|
$
$
|
35,333
54,862
|
0
0
|
||||||||
|
J.
C.
Bouknight
|
SCANA
Ret. Plan
SCANA
SERP
|
2
2
|
$
$
|
31,379
42,836
|
0
0
|
||||||||
|
S.
A.
Byrne
|
SCANA
Ret. Plan
SCANA
SERP
|
11
11
|
$
$
|
110,324
174,521
|
0
0
|
||||||||
(1)
Computed
as of December 31, 2006, the plan measurement date used for financial statement
reporting purposes.
(2)
Present
value calculation determined using current account balances for each Named
Executive Officer as of the end of 2006, based on assumed retirement at normal
retirement age (specified as age 65) and other assumptions as to valuation
method, interest rate and other material factors as set forth in Note 3 under
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCE&G in Part
II above.
The
SCANA
Retirement Plan and Supplemental Executive Retirement Plan are both cash
balance
defined benefit plans. The plans provide for full vesting after five years
of
service or after reaching age 65. All named executive officers are fully
vested
in both plans with the exception of Mr. Bouknight.
Defined
Benefit Retirement Plan
SCANA
sponsors a tax qualified defined benefit retirement plan in which all of
its
subsidiaries, including SCE&G, participate. The plan uses a
mandatory cash balance benefit formula for employees hired on or after
January 1, 2000. Effective July 1, 2000, employees hired prior to
January 1, 2000 were given the choice of remaining under the Retirement
Plan's final average pay formula or switching to the cash balance formula.
All
the Named Executive Officers participate under the cash balance formula of
the
Retirement Plan.
The
cash
balance formula is expressed in the form of a hypothetical account balance.
Account balances are increased monthly by interest and compensation credits.
The
interest rate used for accumulating account balances is determined annually
and
is equal to the average rate for 30-year Treasury Notes for December of the
previous calendar year. Compensation
credits equal 5% of compensation up to the Social Security wage base and
10% of
compensation in excess of the Social Security wage base.
Supplemental
Executive Retirement Plan
In
addition to the Retirement Plan for all employees, SCANA provides a Supplemental
Executive Retirement Plan for certain eligible employees, including the Named
Executive Officers. The Supplemental Executive Retirement Plan is an unfunded
plan that provides for benefit payments in addition to benefits payable under
the qualified Retirement Plan in order to replace benefits lost in the
Retirement Plan because of Internal Revenue Code maximum benefit limitations.
The Supplemental Executive Retirement Plan is discussed under the caption
“- -
Potential Payments Upon Termination or Change in Control - Retirement Benefits,”
and under the caption “- - Compensation Discussion and Analysis - - Retirement
and Other Benefit Plans.”
2006
NONQUALIFIED DEFERRED COMPENSATION
The
following table sets forth information with respect to the Executive Deferred
Compensation Plan:
|
Name
|
Executive
Contributions
in
Last FY
($)(1)
|
Registrant
Contributions
in
Last FY
($)(1)
|
Aggregate
Earnings
in
Last
FY
($)
|
Aggregate
Withdrawals/
Distributions
($)
|
Aggregate
Balance
at
Last
FYE
($)
|
|||||||||||
|
(a)
|
(b)
|
(c)
|
(d)
|
(e)
|
(f)
|
|||||||||||
|
W.
B.
Timmerman
|
$
|
53,220
|
$
|
53,220
|
$
|
155,692
|
0
|
$
|
2,652,609
|
|||||||
|
J.
E.
Addison
|
$
|
13,572
|
$
|
13,387
|
$
|
19,862
|
0
|
$
|
325,102
|
|||||||
|
K.
B.
Marsh
|
$
|
46,962
|
$
|
46,844
|
$
|
143,723
|
0
|
$
|
1,105,338
|
|||||||
|
F.
P.
Mood,
Jr.
|
$
|
23,550
|
$
|
23,550
|
$
|
7,434
|
0
|
$
|
68,533
|
|||||||
|
J.
C.
Bouknight
|
$
|
15,945
|
$
|
15,945
|
$
|
7,471
|
0
|
$
|
62,580
|
|||||||
|
S.
A.
Byrne
|
$
|
52,877
|
$
|
28,842
|
$
|
24,551
|
0
|
$
|
439,168
|
|||||||
(1)
The
amounts reported in Columns (b) and (c) are reflected in the Summary
Compensation Table.
Executive
Deferred Compensation Plan
We
have
adopted the SCANA Corporation Executive Deferred Compensation Plan, in which
our
Named Executive Officers may participate if they choose to do so. The plan
is a
non-qualified deferred compensation plan. Each participant may elect to defer
up
to 25% of that part of his or her eligible earnings (as defined in the 401(k)
plan) that exceeds the limitation on compensation otherwise required under
Internal Revenue Code Section 401(a)(17), and without regard to any deferrals
or
the foregoing of compensation. For 2006, participants could defer on eligible
earnings in excess of $220,000. In addition, a participant may elect to defer
up
to 100% of any performance share award for the year under our Long-Term Equity
Compensation Plan. We match the amount of compensation deferred by each
participant up to 6% of the participant’s eligible earnings in excess of the
limit amount not including any performance share award.
We
record
the amount of each participant’s deferred compensation and the amount we match
in a special ledger. We also credit a rate of return to each participant’s
special ledger account based on hypothetical investment alternatives chosen
by
the participant. The committee that administers the Executive Deferred
Compensation Plan designates various hypothetical investment alternatives
from
which the participants may choose. Using the results of the hypothetical
investment alternatives chosen, we credit each participant’s special ledger
account with the amount it would have earned if the account amount had been
invested in that alternative. If the chosen hypothetical investment alternative
loses money, the participant’s special ledger account is reduced by the
corresponding amount. All amounts credited to a participant’s special ledger
accounts continue to be credited or reduced pursuant to the chosen investment
alternatives until such amounts are paid in full to the participant or his
beneficiary. No actual investments are made. The investment alternatives
are
only used to generate a rate of increase (or decrease) in the special ledger
accounts and amounts paid to participants are solely our obligation. In
connection with this plan, the Board has established a grantor trust (known
as
the “SCANA Corporation Executive Benefit Plan Trust”) for the purpose of
accumulating funds to satisfy the obligations we incur under the Plan. At
any time prior to a change in control we may transfer assets to the trust
to
satisfy all or part of our obligations under the Plan. Notwithstanding the
establishment of the Trust, the right of participants to receive future payments
is an unsecured claim against us. The
trust
has been partially funded with respect to ongoing deferrals and Company matching
funds since October 2001.
In
2006,
the Named Executive Officers’ special ledger accounts were credited with
earnings (or losses) based on the following investment alternatives and rates
of
returns:
INVESCO
Stable Value Trust (4.30%); PIMCO Total Return (3.74%); Dodge & Cox Common
Stock (18.53%); American Century Inc. & Growth Adv. (16.86%); INVESCO 500
Index Trust (15.37%); Pioneer Oak Ridge Large Cap Growth (2.61%); T. Rowe
Price
Mid Cap Value (20.24%); Lord Abbett Growth Opportunity (7.66%); RS Partners
(11.22%); Vanguard Explorer (9.88%); American Funds Europacific Growth (21.87%);
SCANA Corporation Stock (7.60%); Janus Small Cap Value (12.4%); Vanguard
Target
Retirement Income (6.38%); Vanguard Target Retirement 2005 (8.23%); Vanguard
Target Retirement 2015 (11.42%); Vanguard Target Retirement 2025 (13.24%);
Vanguard Target Retirement 2035 (15.24%); Vanguard Target Retirement 2045
(15.98$). The measures for calculating interest or other plan earnings are
based on the investments chosen by the manager of each investment vehicle,
except the SCANA Stock Fund, the earnings of which are based on the value
of
SCANA's common stock.
The
hypothetical investment alternatives may be changed at any time on a prospective
basis by the participants in accordance with the telephone, electronic, and
written procedures and forms adopted by the committee for use by all
participants on a consistent basis.
All
amounts deferred under the Executive Deferred Compensation Plan, matching
contributions and earnings credited to a participant’s special ledger account
are paid, or begin to be paid, to the participant either in a lump sum or
installments for up to 15 years at a later time chosen by the participant;
provided, however, that the deferred amounts are to be paid, or to begin
to be
paid, as soon as practicable following the participant’s death, disability,
retirement or other termination of employment.
A
participant may request and receive, with the approval of the committee,
an
acceleration of the payment of some or all of the participant’s special ledger
account due to severe financial hardship as the result of extraordinary and
unforeseeable circumstances arising as a result of events beyond the
individual’s control. With respect to amounts earned and vested before January
1, 2005, a participant may also obtain payment of his special ledger account
on
an accelerated basis by forfeiting 10% of the amount accelerated or by making
the election to accelerate the payment not less than 12 months before the
payment will be made. Additionally, the plan provides for the acceleration of
payments following a change in control of the Company. The change in control
provisions are discussed under “- - Potential Payments Upon Termination or
Change in Control - - Change in Control Arrangements.”
We
plan
to amend all available distribution and withdrawal options with respect to
amounts earned or vested after 2004 to conform to the requirements for deferred
compensation under Section 409A of the Internal Revenue Code. The Internal
Revenue Service has issued proposed and preliminary guidance under Section
409A.
The extent of any changes needed to conform to Section 409A will not be clear
until after final guidance is issued. Currently, the Internal Revenue Service
requires that changes to conform to Section 409A generally be made by December
31, 2007. However, we were required to operate in good faith compliance from
January 1, 2005 forward, subject to guidance issued by the Internal Revenue
Service.
Potential
Payments Upon Termination or Change in Control
Change
in Control Arrangements
Triggering
Events for Payments under the Key Executive Severance Benefits Plan and the
Supplementary Key Executive Severance Benefits Plan
We
have
adopted the SCANA Corporation Key Executive Severance Benefits Plan and the
SCANA Corporation Supplementary Key Executive Severance Benefits Plan, which
provide for payments to our senior executive officers in connection with
a
change in control of the Company. The Key Executive Severance Benefits Plan
(the
“Severance Plan”) provides for payment of benefits in a lump sum immediately
upon a change in control unless the plan has been terminated prior to the
change
in control. This plan is designed to provide for benefits in the event of
a
change in control that our Board deems to be hostile. In the event of a change
in control that our Board deems to be friendly, we anticipate that the Board
would terminate the Severance Plan prior to the change in control. If the
Severance Plan is terminated, the Supplementary Key Executive Severance Benefits
Plan (the “Supplementary Severance Plan”) would provide for payment of benefits
if, within 24 months after the change in control, we terminate a senior
executive officer’s employment without just cause or if the senior executive
officer terminates his or her employment for good reason.
Both
plans provide that a “change in control” will be deemed to occur under the
following circumstances:
| · |
if
any person or entity becomes the beneficial owner, directly or indirectly,
of 25% or more of the combined voting power of the outstanding shares
of
SCANA common stock;
|
| · |
if,
during a consecutive two-year period, a majority of our directors
cease to
be individuals who either (a) were
|
directors
on the Board at the beginning of such period, or (b) became directors after
the
beginning of such period but whose election by the Board, or nomination for
election by our shareholders, was approved by at least two-thirds of the
directors then still in office who either were directors at the beginning
of
such period, or whose election or nomination for election was previously
so
approved;
| · |
if
SCANA shareholders approve (a) a merger or consolidation of SCANA
with
another corporation (except a merger or consolidation in which SCANA
outstanding voting shares prior to such transaction continue to represent
at least 80% of the combined voting power of the surviving entity's
outstanding voting shares after such transaction), (b) a plan of
complete
liquidation of SCANA, or (c) an agreement to sell or dispose of all
or
substantially all of SCANA’s assets; or
|
| · |
if
SCANA’s shareholders approve a plan of complete liquidation, or sale or
disposition of, South Carolina Electric & Gas Company, Carolina Gas
Transmission Corporation, or any of SCANA’s other subsidiaries that the
Board designates to be a material subsidiary. (This last provision
would
constitute a change in control only with respect to participants
exclusively assigned to the affected subsidiary.)
|
As
noted
above, benefits under the Supplementary Severance Plan would be triggered
if we
terminated the Severance Plan prior to a change in control, and, within 24
months after the change in control, we terminated the senior executive officer’s
employment without just cause or if the senior executive officer terminated
his
or her employment for good reason. Under the plan, we would be deemed to
have
“just cause” for terminating the employment of a senior executive officer if he
or she:
| · |
willfully
and continually failed to perform his or her duties after we made
demand
for substantial performance;
|
| · |
willfully
engaged in conduct that is materially injurious to us;
or
|
| · |
were
convicted of a felony or certain
misdemeanors.
|
A
senior
executive officer would be deemed to have “good reason” for terminating his or
her employment if:
| · |
he
or she were assigned to duties inconsistent with his or her duties,
or had
a reduction or alteration in the nature or status of his or her
responsibilities, from those in effect 90 days prior to the change
in
control;
|
| · |
we
reduced his or her base salary as in effect 30 days prior to the
occurrence of certain preliminary actions preceding the change in
control
(such as the execution of agreements relating to a change in control,
public announcements by us of our intentions, transfers of securities
representing at least 8½% of SCANA's common stock or the adoption of
board resolutions with respect thereto);
|
| · |
after
the change in control, we required him or her to be based more than
25
miles from his or her location as of the effective date of the
Supplementary Severance Plan;
|
| · |
we
failed to continue to offer any annual or long-term incentive programs
for
officers which were in effect on the effective date of the change
in
control, or other employee benefit plans, policies, practices or
arrangements in which he or she participates, unless similar plans
of
equal value are put in place, or we failed to permit him or her to
continue participation on substantially the same basis as existed
on the
date of the change in control;
|
| · |
we
failed to obtain a satisfactory agreement from any successor to assume
and
perform the Supplementary Severance Plan;
or
|
| · |
we
purported to terminate him or her without using a notice of termination
that satisfies the requirements of the Supplementary Severance
Plan.
|
Potential
Benefits Payable
The
benefits we would be required to pay our senior executive officers under
the
Severance Plan immediately upon a change in control are as follows:
| · |
An
amount intended to approximate three times the sum of: (i) his or her
annual base salary (before reduction for certain pre-tax deferrals)
and
(ii) his or her full targeted annual incentive award, in each case as
in effect for the year in which the change in control
occurs;
|
| · |
An
amount equal to the present value as of the date of the change in
control
of his or her accrued benefit, if any, under our Supplemental Executive
Retirement Plan, determined prior to any offset for amounts payable
under
the SCANA Retirement Plan, increased by the present value of the
additional projected pay credits and periodic interest credits that
would
otherwise accrue under the plan (based on the plan's actuarial
assumptions) assuming that he or she remained employed until reaching
age
65, and reduced by his or her cash balance account under the SCANA
Retirement Plan; and
|
| · |
An
amount equal to the projected cost for medical, long-term disability
and
certain life insurance coverage for three years following the change
in
control as though he or she had continued to be our employee.
|
In
addition to the benefits above, immediately upon a change in control prior
to
which we had not terminated the Severance Plan (unless their agreements with
us
provide otherwise), our senior executive officers would also be entitled
to
benefits under our other plans in which they participate as follows:
| · |
A
benefit distribution of all amounts credited to his or her Executive
Deferred Compensation Plan ledger account as of the date of the change
in
control;
|
| · |
A
benefit distribution under the Long-Term Equity Compensation Plan
equal to
100% of the target performance share award for all performance periods
not
completed as of the date of the change in control, if any;
|
| · |
A
benefit distribution under the Short-Term Annual Incentive Plan equal
to
100% of the target award in effect as of the date of the change in
control;
|
| · |
Under
the Long-Term Equity Compensation Plan and related agreements, all
nonqualified stock options awarded and non-vested target performance
shares would become immediately exercisable or vested and remain
exercisable throughout their original term or, in the case of performance
shares, vested and payable within 30 days of the change in control;
and
|
| · |
Any
amounts previously earned, but not yet paid, under the terms of any
of our
other plans or programs.
|
Under
the
Supplementary Severance Plan, senior executive officers would also be entitled
to all of the benefits described above. In addition, interest would be paid
on
the benefits payable under the Executive Deferred Compensation Plan at a
rate
equal to the sum of the prime interest rate as published in the Wall Street
Journal on the most recent publication date prior to the date of the change
in
control plus 3%, calculated through the end of the month preceding the month
in
which the benefits are distributed. Any amounts payable under the Supplementary
Severance Plan would be reduced by all amounts, if any, received under the
Severance Plan.
In
addition, benefit distributions to senior executive officers under either
the
Severance Plan or the Supplementary Severance Plan would also include payment
of
an amount (a "gross-up payment") reimbursing him or her for the amount of
anticipated excise tax imposed under Section 4999 of the Internal Revenue
Code
(or any similar tax) on such benefits and the gross-up payment, and any income
and employment tax and excise tax due with respect to the gross-up
payment.
Calculation
of Benefits Potentially Payable to our Named Executive Officers if a Triggering
Event had Occurred as of December 29, 2006
Severance
Plan
If
we had
been subject to a change in control as of December 29, 2006, and the Severance
Plan had not been terminated, our Named Executive Officers would have been
immediately entitled to the benefits outlined below.
Mr.
Timmerman
would have been entitled to the following: an amount equal to three times
his
base salary and target short-term incentive award - $5,565,000; an amount
equal
to the excess payable under the Supplemental Executive Retirement Plan as
calculated under the assumptions described above - $812,000; an amount equal
to
insurance continuation benefits for three years - $34,000; an amount equal
to
the value of 100% of his target performance shares under the Long-Term Equity
Compensation Plan - $5,754,000; and
anticipated excise tax and gross-up payment - $5,290,000. The total value
of
these change in control benefits would have been $17,455,000. In addition,
Mr.
Timmerman would have been paid amounts previously earned, but not yet paid,
as
follows: 2006 actual short-term annual incentive award - $596,607; Executive
Deferred Compensation Plan account balance - $2,652,609; Supplemental Executive
Retirement Plan and Retirement Plan account balances- $3,056,000; vacation
accrual - $69,000; as well as his 401(k) Plan account balance.
Mr.
Addison would have been entitled to the following: an amount equal to three
times his base salary and target short-term incentive award - $1,274,000;
an
amount equal to the excess payable under the Supplemental Executive Retirement
Plan as calculated under the assumptions described above - $545,000; an amount
equal to insurance continuation benefits for three years - $61,000; an amount
equal to the value of 100% of his target performance shares under the Long-Term
Equity Compensation Plan - $589,000; and anticipated excise tax and gross-up
payment - $1,087,000. The total value of these change in control benefits
would
have been $3,556,000. In addition, Mr. Addison would have been paid amounts
previously earned, but not yet paid, as follows: 2006 actual short-term annual
incentive award - $97,705; Executive Deferred Compensation Plan account
balance - $325,102; Supplemental Executive Retirement Plan and Retirement
Plan
account balances- $246,000; vacation accrual - $9,000; as well as
his 401(k) Plan account balance.
Mr.
Marsh
would have been entitled to the following: an amount equal to three times
his
base salary and target short-term incentive award - $2,579,000; an amount
equal
to the excess payable under the Supplemental Executive Retirement Plan as
calculated under the assumptions described above - $905,000; an amount equal
to
insurance continuation benefits for three years - $46,000; an amount equal
to
the value of 100% of his target performance shares under the Long-Term Equity
Compensation Plan - $1,913,000; and anticipated excise tax and gross-up payment
- $2,296,000.
The
total value of these change in control benefits would have been $7,739,000.
In
addition, Mr. Marsh would have been paid amounts previously earned, but not
yet
paid, as follows: 2006 actual short-term annual incentive award - $234,206;
Executive Deferred Compensation Plan account balance - $1,105,338; Supplemental
Executive Retirement Plan and Retirement Plan account balances -
$934,000; vacation accrual - $9,000; as well as his 401(k) Plan
account balance.
Mr.
Mood
would have been entitled to the following: an amount equal to three times
his
base salary and target short-term incentive award - $1,575,000; an amount
equal
to the excess payable under the Supplemental Executive Retirement Plan as
calculated under the assumptions described above - $0; an amount equal to
insurance continuation benefits for three years - $35,000; an amount equal
to
the value of 100% of his target performance shares under the Long-Term Equity
Compensation Plan - $853,000; and
anticipated excise tax and gross-up payment - $1,090,000. The total value
of
these change in control benefits would have been $3,553,000. In addition,
Mr.
Mood would have been paid amounts previously earned, but not yet paid, as
follows: 2006 actual short-term annual incentive award - $122,500; Executive
Deferred Compensation Plan account balance - $68,533; Supplemental Executive
Retirement Plan and Retirement Plan account balances - $90,000; vacation
accrual - $0; as well as his 401(k) Plan account balance.
Mr.
Bouknight would have been entitled to the following: an amount equal to three
times his base salary and target short-term incentive award - $1,305,000;
an
amount equal to the excess payable under the Supplemental Executive Retirement
Plan as calculated under the assumptions described above - $445,000; an amount
equal to insurance continuation benefits for three years - $44,000; an amount
equal to the value of 100% of his target performance shares under the Long-Term
Equity Compensation Plan - $644,000; and anticipated excise tax and gross-up
payment - $1,043,000. The total value of these change in control benefits
would
have been $3,481,000. In addition, Mr. Bouknight would have been paid amounts
previously earned, but not yet paid, as follows: 2006 actual short-term annual
incentive award - $101,500; Executive Deferred Compensation Plan account
balance
- $62,580; Supplemental Executive Retirement Plan and Retirement Plan account
balances - $0; vacation accrual - $7,000; as well as his 401(k) Plan
account balance.
Mr.
Byrne
would have been entitled to the following: an amount equal to three times
his
base salary and target short-term incentive award - $1,922,000; an amount
equal
to the excess payable under the Supplemental Executive Retirement Plan as
calculated under the assumptions described above - $807,000; an amount equal
to
insurance continuation benefits for three years - $63,000; an amount equal
to
the value of 100% of his target performance shares under the Long-Term Equity
Compensation Plan - $1,119,000; and anticipated excise tax and gross-up payment
- $1,716,000. The total value of these change in control benefits would have
been $5,627,000. In addition, Mr. Byrne would have been paid amounts previously
earned, but not yet paid, as follows: 2006 actual short-term annual incentive
award - $168,168; Executive Deferred Compensation Plan account balance -
$439,168; Supplemental Executive Retirement Plan and Retirement Plan account
balances - $353,000; vacation accrual - $17,000; as well as his 401(k) Plan
account balance.
In
addition to the foregoing benefits, all option and stock awards set forth
in the
“2006 Outstanding Equity Awards at Fiscal Year-End” table would have vested for
each Named Executive Officer.
Supplementary
Severance Plan
If
(i) we
had been subject to a change in control in the past 24 months, (ii) the
Severance Plan had been terminated prior to the change in control, and (iii)
as
of December 29, 2006, either we had terminated the employment of any of our
Named Executive Officers without just cause or they had terminated their
employment for good reason, such terminated Named Executive Officer would
have
been immediately entitled to all of the benefits outlined above, together
with
an amount equal to an increase in the amount payable with respect to his
Executive Deferred Compensation Plan account, calculated as outlined above.
The
actual amount of any such additional payment would depend upon the date on
which
employment of the Named Executive Officer terminated subsequent to the change
in
control.
Retirement
Benefits
Supplemental
Executive Retirement Plan
The
SCANA
Corporation Supplemental Executive Retirement Plan (the “SERP”) is an unfunded
nonqualified deferred compensation plan. The SERP was established for the
purpose of providing supplemental
retirement income to certain of our employees, including the Named Executive
Officers, whose benefits under the Retirement Plan are limited in accordance
with the limitations imposed by the Internal Revenue Code on the amount of
annual retirement benefits payable to employees from qualified pension plans
or
on the amount of annual compensation that may be taken into account for all
qualified plan purposes, or by certain other design limitations on determining
compensation under the Retirement Plan.
Subject
to the terms of the SERP, a participant becomes eligible to receive benefits
under the SERP upon termination of his or her employment with us (or at such
later date as may be provided in a participant’s agreement with us), if the
participant has become vested in his or her accrued benefit under the Retirement
Plan prior to termination of employment. However, if a participant is
involuntarily terminated following or incident to a change in control and
prior
to becoming fully vested in his or her accrued benefit under the Retirement
Plan, the participant will automatically become fully vested in his benefit
under the SERP and a benefit will be payable under the SERP. The term “change in
control” has the same meaning in the SERP as in the Severance Plan and the
Supplementary Severance Plan. See the discussion under “Change in Control
Arrangements.”
Unless
otherwise provided in a participant agreement, the amount of any benefit
payable
to a participant under the SERP will be determined as of the date he or she
first becomes eligible to receive benefits under the SERP, and will be equal
to
(i) the cash balance account that otherwise would have been payable under
the
Retirement Plan as of such determination date, based on compensation and
disregarding the limitations imposed by the Internal Revenue Code on the
amount
of annual retirement benefits payable to employees from qualified pension
plans
and on the amount of annual compensation that may be taken into account for
all
qualified plan purposes, minus (ii) the participant’s cash balance account
determined under the Retirement Plan as of such determination date. For purposes
of the SERP, “compensation” is defined as determined
under the Retirement Plan, without regard to the limitation under Section
401(a)(17) of the Internal Revenue Code, including any amounts of compensation
otherwise deferred under any non-qualified deferred compensation plan (excluding
the SERP).
The
benefit payable to a participant under the SERP will be paid, or commence
to be
paid, as of the first day of the calendar month following the date the
participant first becomes eligible to receive a benefit under the SERP. With
respect to amounts earned and vested before January 1, 2005, the participant
may
elect, in accordance with procedures we establish, to receive a distribution
of
such benefit in either of the following two forms of payment:
| · |
A
single sum distribution of the value of the participant’s benefit under
the SERP determined as of the last day of the month preceding the
date he
or she first becomes eligible to receive benefits; or
|
| · |
A
lifetime annuity benefit with an additional death benefit payment
as
follows: A lifetime annuity that is the actuarial equivalent of the
participant’s single sum amount which provides for a monthly benefit
payable for the participant’s life, beginning on the first day of the
month following the date on which he or she first becomes eligible
to
receive benefits. In addition to this life annuity, commencing on
the
first day of the month following the participant’s death, his or her
designated beneficiary will receive a benefit of 60% of the amount
of the
participant’s monthly payment continuing for a 15 year period. If,
however, the beneficiary dies before the end of the 15 year period,
the
lump sum value of the remaining monthly payments of the survivor
benefit
will be paid to the beneficiary’s estate. The participant’s life annuity
will not be reduced to reflect the “cost” of providing the 60% survivor
benefit feature. “Actuarial equivalent” is defined by the SERP as equality
in value of the benefit provided under the SERP based on actuarial
assumptions, methods, factors and tables that would apply under the
Retirement Plan under similar
circumstances.
|
For
amounts earned and vested after January 1, 2005, the amounts are subject
to
Internal Revenue Service Code Section 409A and the choice between lump sum
and
annuity is not available. The new distribution options have not yet been
determined.
Unless
otherwise provided in a participant agreement, if a participant dies before
the
first day of the calendar month after he or she becomes eligible to receive
benefits under the SERP, a single sum distribution equal to the value of
the
benefit that otherwise would have been payable under the SERP will be paid
to
the participant’s designated beneficiary as soon as administratively practicable
following the participant’s death. With respect to SERP amounts earned and
vested on or after January 1, 2005, the available distribution options will
be
limited in accordance with Section 409A of the Internal Revenue
Code.
Calculation
of Benefits Potentially Payable to our Named Executive Officers if a Triggering
Event had Occurred as of December 29, 2006
The
lump
sum or annuity amounts that would have been payable under the SERP to each
of
our Named Executive Officers if they had become eligible for benefits as
of
December 29, 2006 are set forth below. Also set forth below are the payments
that would be made to each Named Executive Officer’s designated beneficiary if
the officer had died December 29, 2006.
For
Mr.
Timmerman, the lump sum amount would have been $2,216,155, or the monthly
payments would have been $13,536 for the remainder of his lifetime. In the
event
he had died December 29, 2006 after becoming eligible for benefits, his
designated beneficiary would receive monthly payments of $8,121 for up to
15
years. If Mr. Timmerman had died December 29, 2006 before becoming eligible
for
benefits, his beneficiary would have been entitled to a lump sum payment
equal
to the amount shown above.
For
Mr.
Addison, the lump sum amount would have been $85,796, or the monthly payments
would have been $417 for the remainder of his lifetime. In the event he had
died
December 29, 2006 after becoming eligible for benefits, his designated
beneficiary would receive monthly payments of $250 for up to 15 years. If
Mr.
Addison had died December 29, 2006 before becoming eligible for benefits,
his
beneficiary would have been entitled to a lump sum payment equal to the amount
shown above.
For
Mr.
Marsh, the lump sum amount would have been $435,636, or the monthly payments
would have been $2,264 for the remainder of his lifetime. In the event he
had
died December 29, 2006 after becoming eligible for benefits, his designated
beneficiary would receive monthly payments of $1,359 for up to 15 years.
If Mr.
Marsh had died December 29, 2006 before becoming eligible for benefits, his
beneficiary would have been entitled to a lump sum payment equal to the amount
shown above.
For
Mr.
Mood, the lump sum amount would have been $54,862, or the monthly payments
would
have been $420 for the remainder of his lifetime. In the event he had died
December 29, 2006 after becoming eligible for benefits, his designated
beneficiary would receive monthly payments of $252 for up to 15 years. If
Mr.
Mood had died December 29, 2006 before becoming eligible for benefits, his
beneficiary would have been entitled to a lump sum payment equal to the amount
shown above.
Mr.
Bouknight was not vested so no payments would have been due.
For
Mr.
Byrne, the lump sum amount would have been $216,129, or the monthly payments
would have been $1,062 for the remainder of his lifetime. In the event he
had
died December 29, 2006 after becoming eligible for benefits, his designated
beneficiary would receive monthly payments of $637 for up to 15 years. If
Mr.
Byrne had died December 29, 2006 before becoming eligible for benefits, his
beneficiary would have been entitled to a lump sum payment equal to the amount
shown above.
Executive
Deferred Compensation Plan
The
SCANA
Corporation Executive Deferred Compensation Plan is described in the narrative
following the 2006 Nonqualified Deferred Compensation table. As discussed
in
that section, amounts deferred under the plan are required to be paid, or
begin
to be paid, as soon as practicable following a participant’s death, disability,
retirement or other termination of employment. Such payments are made in
the
form of a single sum cash distribution. However, at the election of the
participant, payments payable after the participant’s death after reaching
retirement age, retirement, or termination of employment as a result of
disability, may be made in the form of annual installment payments over a
period
not to exceed 15 years. The plan defines “retirement age” as the later of
reaching age 55 and 20 years of vesting service or attainment of age 65,
and
defines “retirement” as termination of employment after reaching retirement age.
All amounts credited to a participant’s special ledger account continue to be
hypothetically invested among the investment alternatives until such amounts
are
paid in full to the participant or his or her beneficiary. The terms of the
plan
governing distributions and deferrals are subject to further modification
to
conform to the requirements of Section 409A of the Internal Revenue
Code.
The
“Aggregate Balance at Last FYE” column of the 2006 Nonqualified Deferred
Compensation table shows the amounts that would have been payable under the
Executive Deferred Compensation Plan to each of our Named Executive Officers
if
they had died after reaching retirement age, retired, or if their employment
had
been terminated as a result of disability, as of December 29, 2006, and if
they
had been paid using the single sum form of payment. If the Named Executive
Officers instead chose payment of the deferrals in annual installments, the
installment payments over the payment periods selected by the Named Executive
Officers are estimated as set forth below: Mr. Timmerman - $530,522; Mr.
Addison
- $65,020; Mr. Marsh - $221,068; Mr. Mood - 13,707; Mr. Bouknight - $12,516;
Mr.
Byrne - $87,834.
DIRECTOR
COMPENSATION
Board
Fees
Our
Board
reviews director compensation every year with guidance from the Nominating
Committee. In making its recommendations, the Committee is required by SCANA's
Governance Principles to consider that compensation should fairly pay directors
for work required in a company of SCANA's size and scope, compensation
should align directors' interests with the long-term interests of shareholders,
and the compensation structure should be transparent and easy for shareholders
to understand. We also consider the risk inherent in board service. Every
other
year the Nominating Committee considers relevant public data in making
recommendations.
Officers
who are also directors do not receive additional compensation for their service
as directors. All directors of SCANA also serve as directors of SCE&G
without additional compensation. Effective January 1, 2005,
compensation for non-employee directors consists of the following:
| · |
an
annual retainer of $45,000 (required to be paid in shares of SCANA's
common stock effective January 1, 2006);
|
| · |
a
fee of $6,500 for attendance at regular quarterly meetings of the
Board of
Directors;
|
| · |
a
fee of $6,000 for attendance at all-day meetings of the Board of
Directors
other than regular meetings;
|
| · |
a
fee of $3,000 for attendance at half-day meetings of the Board other
than
regular meetings;
|
| · |
a
fee of $3,000 for attendance at a committee meeting held on a day
other
than a day a regular meeting of the Board is
held;
|
| · |
a
fee of $300 for telephonic meetings of the Board of Directors or
a
committee that last fewer than 30
minutes;
|
| · |
a
fee of $600 for telephonic meetings of the Board of Directors or
a
committee that last more than 30 minutes;
and
|
| · |
reimbursement
of reasonable expenses incurred in connection with all of the
above.
|
Unless
deferred at the director’s election pursuant to the terms of the
SCANA Director Compensation and Deferral Plan, directors’ retainer fees are
paid annually in shares of SCANA's common stock, and meeting attendance and
conference fees are paid at such times as the Board determines in cash or
SCANA
common stock at the director’s election.
Director
Compensation and Deferral Plans
Since
January 1, 2001, our non-employee director compensation and related
deferrals have been governed by the SCANA Director Compensation and Deferral
Plan. Amounts deferred by directors in previous years under the SCANA Voluntary
Deferral Plan continue to be governed by that plan. During 2006, the only
director with funds remaining in the SCANA Voluntary Deferral Plan was Mr.
Bennett.
Under
the
SCANA Director Compensation and Deferral Plan, a director may make an annual
irrevocable election to defer the annual retainer fee, which (effective
January 1, 2006) is required to be paid in SCANA's common stock, in a
hypothetical investment in SCANA's common stock, with distribution from the
plan
to be ultimately payable in actual shares of SCANA's common stock. A director
also may elect to defer up to 100% of meeting attendance and conference fees
with distribution from the plan to be ultimately payable in either SCANA's
common stock or cash. Amounts payable in SCANA's common stock accrue earnings
during the deferral period at our dividend rate, which directors may choose
to
have paid in cash when accrued or retained to invest in additional hypothetical
shares of SCANA's common stock. Amounts payable in cash accrue interest until
paid. Hypothetical shares do not have voting rights.
During
2006, Messrs. Amick, Bennett, Burkhardt, Sloan, York and Ms. Miller
elected to defer 100% of their
compensation
and earnings and Messrs. Hagood and Stowe deferred a portion of their earnings
under the SCANA Director Compensation and Deferral Plan.
As
previously discussed, we
plan to
amend all available distribution and withdrawal options with respect to amounts
earned or vested after 2004 under all of the deferred compensation plans
to
conform to the requirements for deferred compensation under Section 409A
of the
Internal Revenue Code.
Endowment
Plan
Upon
election to a second term, a director becomes eligible to participate in
the
SCANA Director Endowment
Plan, which provides for us to make tax deductible, charitable contributions
totaling $500,000 to institutions
of higher education designated by the director. The plan is intended to
reinforce our commitment to quality higher
education and to enhance our ability to attract and retain qualified board
members. A portion is contributed upon retirement of the director and the
remainder upon the director's death. As of December 31, 2006, our obligation
under the plan was $4,462,356. The plan is funded through insurance
policies on the lives of the directors. The 2006 premium for such insurance
was
$333,928 which was offset by the receipt of insurance proceeds in the amount
of
$754,498. The insurance proceeds were received in 2006 after the death of
a
director in 2005. Currently the premium estimate for 2007 is
$95,000.
Designated
institutions of higher education in South Carolina, North Carolina and Georgia
must be approved by SCANA's Chief Executive Officer. Institutions in other
states must be approved by the Human Resources Committee. The designated
institutions are reviewed on an annual basis by the Chief Executive Officer
to
assure compliance with the intent of the plan.
2006
DIRECTOR COMPENSATION
The
following table sets forth the compensation we paid to each of our non-employee
directors in 2006.
|
Name
|
Fees
Earned
or
Paid
in Cash
($)
|
Stock
Awards
($)(1)
|
Option
Awards
($)
|
Non-Equity
Incentive Plan Compensation
($)
|
Change
in Pension
Value
and Nonqualified Deferred Compensation Earnings(2)
($)
|
All
Other Compensation
($)
|
Total
($)
|
|||||||||||||||
|
(a)
|
(b
|
)
|
(c
|
)
|
(d
|
)
|
(e
|
)
|
(f
|
)
|
(g
|
)
|
(h
|
)
|
||||||||
|
B.
L. Amick
|
$
|
43,500
|
$
|
45,000
|
|
|||||||||||||||||
|
J.
A. Bennett
|
$
|
71,000
|
$
|
45,000
|
$
|
3,830
|
||||||||||||||||
|
W.
C. Burkhardt
|
$
|
75,800
|
$
|
45,000
|
|
|||||||||||||||||
|
S.
A. Decker
|
$
|
77,600
|
$
|
45,000
|
|
|||||||||||||||||
|
D.
M. Hagood
|
$
|
73,400
|
$
|
45,000
|
|
|||||||||||||||||
|
W.
H. Hipp
|
$
|
38,000
|
$
|
45,000
|
|
|||||||||||||||||
|
L.
M. Miller
|
$
|
81,800
|
$
|
45,000
|
||||||||||||||||||
|
M.
K. Sloan
|
$
|
76,400
|
$
|
45,000
|
||||||||||||||||||
|
H.
C. Stowe
|
$
|
57,900
|
$
|
45,000
|
||||||||||||||||||
|
G.
S. York
|
$
|
68,000
|
$
|
45,000
|
|
|||||||||||||||||
(1) The
annual retainer of $45,000 is required to be paid in SCANA's common stock.
Shares were purchased on January 12, 2006 at a weighted average purchase
price
of $40.46 in order to satisfy the retainer fee obligation.
(2) Mr.
Bennett is the only Director who elected to defer director fees into a cash
deferral account. Pursuant to the terms of the deferral plan, the earnings
are
above market as defined by the rules. The amounts shown above represent Mr.
Bennett’s above-market earnings on his deferrals into the cash deferral account
($2,404) as well as his earnings on prior cash deferrals into the prior SCANA
Voluntary Deferral Plan ($1,426).
RELATED STOCKHOLDER
MATTERS
SCANA:
Information required by Item 12 is incorporated herein by reference to the
caption "SHARE OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT" in
SCANA's definitive proxy statement for the 2007 annual meeting of
shareholders.
Equity
securities issuable under SCANA's compensation plans at December 31, 2006
are summarized as follows:
|
Plan
Category
|
Number
of securities
to
be issued
upon
exercise
of
outstanding
options,
warrants
and
rights
|
Weighted-average
exercise
price
of
outstanding options, warrants
and
rights
|
Number
of securities
remaining
available
for
future issuance under equity compensation plans
(excluding
securities
reflected
in column (a))
|
|
|
(a)
|
(b)
|
(c)
|
|
Equity
compensation plans approved by security holders:
|
|||
|
Long-Term
Equity Compensation Plan
|
385,940
|
27.56
|
3,210,827
|
|
Non-Employee
Director Compensation Plan
|
n/a
|
n/a
|
113,883
|
|
Equity
compensation plans not approved by security holders
|
n/a
|
n/a
|
n/a
|
|
Total
|
385,940
|
27.56
|
3,324,710
|
SCE&G:
All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table lists shares of SCANA common stock beneficially owned on
February 22, 2007 by each director and each person named in the Summary
Compensation table in Item 11. EXECUTIVE COMPENSATION.
|
Name
of
Beneficial
Owner
|
Amount
and Nature of Beneficial Ownership(1)
(2) (3) (4) (5)
|
Percent
of Class
|
|
W.
B. Timmerman
|
61,090
|
*
|
|
J.
E. Addison
|
14,040
|
*
|
|
K.
B. Marsh
|
19,156
|
*
|
|
F.
P. Mood, Jr.
|
1,568
|
*
|
|
J.
C. Bouknight
|
1,540
|
*
|
|
S.
A. Byrne
|
31,467(3)
|
*
|
|
B.
L. Amick
|
11,669
|
*
|
|
J.
A. Bennett
|
3,808
|
*
|
|
W.C.
Burkhardt
|
13,122
|
*
|
|
S.
A. Decker
|
2,205
|
*
|
|
D.
M. Hagood
|
1,541
|
*
|
|
W.
H. Hipp
|
15,773
|
*
|
|
L.
M. Miller
|
3,738
|
*
|
|
M.
K. Sloan
|
1,910
|
*
|
|
H.
C. Stowe
|
2,850
|
*
|
|
G.
S. York
|
13,770
|
*
|
|
All
executive officers and directors as a group (18 persons)
|
222,076(6)
|
*
|
*Less
than 1%
|
(1)
|
Includes
shares purchased through February 22, 2007, by the Trustee under
SCANA's
Stock Purchase Savings Plan.
|
(2) Hypothetical
shares acquired under the Director Compensation and Deferral Plan are not
included in the above table. These hypothetical shares do not have voting
rights. As of February 22, 2007, each of the following directors had acquired
under the plan the number of hypothetical shares following his or her name:
Messrs. Amick 15,575; Bennett 13,736; Burkhardt 18,594;
Hagood 5,378; Hipp 12,022; Sloan 17,776; Stowe 13,146;
and York 17,927; Mrs. Decker 0; and
Ms. Miller 18,823.
(3) Includes
shares subject to options that are currently exercisable or that will become
exercisable within 60 days in the following amounts: Mr. Byrne
21,492.
(4) Hypothetical
shares acquired under the Executive Deferred Compensation Plan are not included
in the above table. These hypothetical shares do not have voting rights.
As of
February 22, 2007, each of the following officers had acquired under the
plan
the number of hypothetical shares following his name:
Messrs. Timmerman 41,964; Addison 654; Marsh 5,157; Mood 0;
Bouknight 0; and Byrne 8,368.
(5) Includes
shares owned by close relatives, the beneficial ownership of which is disclaimed
by the director, nominee or named executive officer, as follows:
Mr. Amick-480. Also includes 2,000 shares held in a trust for the benefit
of a family member of Mr. Timmerman, of which Mr. Timmerman
serves as Trustee.
(6) Includes
a total of 21,492 shares subject to options that are currently exercisable
or that will become exercisable within 60 days.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
Related
Transactions
We
require that each senior executive officer, director and director nominee
complete an annual questionnaire and report all transactions with SCANA and
any
of its subsidiaries, including SCE&G, in which such persons (or their
immediate family members) had or will have a direct or indirect material
interest (except for salaries, directors’ fees and dividends on SCANA stock).
Our General Counsel reviews responses to the questionnaires, and if any such
transactions are disclosed, they are reviewed by the Nominating Committee,
and
if appropriate, submitted to the Board for approval. The Company does not,
however, have a formal written policy or procedure for approval or ratification
of such transactions.
The
types
of transactions that have been reviewed in the past include the purchase
and
sale of goods, services or property from companies for which our directors
serve
as executive officers or directors, the purchase of financial services and
access to lines of credit from banks for which our directors serve as executive
officers or directors, and the employment of family members of executive
officers or directors.
There
were no such transactions during the year ended December 31,
2006.
Director
Independence
Each
of the
directors listed in Item 10 is “independent”, as defined in the New York Stock
Exchange Listing Standards, except William B. Timmerman.
ITEM
14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
SCANA:
The information required by Item 14 is incorporated herein by reference to
"PROPOSAL 2 - APPROVAL OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM" in SCANA's definitive proxy statement for the 2007 annual
meeting of shareholders.
SCANA's
Audit Committee Charter requires the Audit Committee to pre-approve all auditing
services and permitted non-audit services (including the fees and terms thereof)
to be performed by the independent registered accounting firm. Pursuant to
a
policy adopted by the Audit Committee, its chairman may pre-approve the
rendering of services on behalf of the Audit Committee. Decisions to pre-approve
the rendering of services by the chairman are presented to the Audit Committee
at each of its scheduled meetings.
Independent
Registered Public Accounting Firm’s Fees
The
following table sets forth the aggregate fees charged to SCE&G for the
fiscal years ended December 31, 2006 and 2005 by Deloitte & Touche
LLP, the member firms of Deloitte Touche Tohmatsu, and their respective
affiliates.
|
SCE&G
|
||||||||||
|
|
|
2006
|
2005
|
|
||||||
|
Audit
Fees(1)
|
|
$
|
1,424,242
|
|
$
|
1,389,564
|
|
|||
|
Audit-Related
Fees(2)
|
|
|
42,471
|
|
|
50,073
|
|
|||
|
Tax
Fees(3)
|
|
|
58,672
|
|
|
51,727
|
|
|||
|
Total
Fees
|
|
$
|
1,523,385
|
|
$
|
1,491,364
|
|
|||
|
(1)
|
Fees
for audit services billed in 2006 and 2005 consisted of audits of
annual
financial statements, comfort letters, statutory and regulatory audits,
consents and other services related to Securities and Exchange Commission
("SEC") filings and accounting
research.
|
(2) Fees
primarily for employee benefit plan audits for 2006 and 2005.
(3) Fees for
tax compliance and tax research services.
In
2006
and 2005, all of the Audit Fees, Audit Related Fees and Tax Fees were approved
by the Audit Committee.
PART
IV
ITEM
15. EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES
(a) The
following documents are filed or furnished as a part of this
Form 10-K:
(1) Financial
Statements and Schedules:
The
Report of Independent Registered Public Accounting Firm on the financial
statements for SCANA and SCE&G are listed under Item 8 herein.
The
financial statements and supplementary financial data filed as part of this
report for SCANA and SCE&G are listed under Item 8 herein.
The
financial statement schedules filed as part of this report for SCANA and
SCE&G begin on the following page.
(2) Exhibits
Exhibits
required to be filed or furnished with this Annual Report on Form 10-K are
listed in the Exhibit Index following the signature page. Certain of such
exhibits which have heretofore been filed with the Securities and Exchange
Commission (SEC) and which are designated by reference to their exhibit number
in prior filings are incorporated herein by reference and made a part
hereof.
Pursuant
to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the
annual report for SCANA's employee stock purchase plan will be furnished under
cover of Form 10-K/A to the SEC when the information becomes
available.
As
permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments
defining the rights of holders of long-term debt of less than 10% of the total
consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G,
for itself and its consolidated affiliates, have been omitted and SCANA and
SCE&G agree to furnish a copy of such instruments to the SEC upon
request.
Schedule II—Valuation
and Qualifying Accounts
|
Additions
|
||||||||||||||||
|
Description
|
Beginning
Balance
|
Charged
to
Income
|
Charged
to
Other
Accounts
|
Deductions
from
Reserves
|
Ending
Balance
|
|||||||||||
|
SCANA:
|
|
|
|
|
|
|||||||||||
|
Reserves
deducted from related assets on the balance sheet:
|
|
|
|
|
|
|||||||||||
|
Uncollectible
accounts
|
|
|
|
|
|
|||||||||||
|
2006
|
$
|
24,863,825
|
$
|
16,935,990
|
-
|
$
|
27,811,236
|
$
|
13,988,579
|
|||||||
|
2005
|
15,740,636
|
26,705,178
|
-
|
17,581,989
|
24,863,825
|
|||||||||||
|
2004
|
16,398,983
|
16,181,865
|
-
|
16,840,212
|
15,740,636
|
|||||||||||
|
|
||||||||||||||||
|
Reserve
for investment impairment
|
||||||||||||||||
|
2006
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
|
2005
|
-
|
-
|
-
|
-
|
-
|
|||||||||||
|
2004
|
$
|
125,000
|
-
|
-
|
$
|
125,000
|
-
|
|||||||||
|
|
||||||||||||||||
|
Reserves
other than those deducted from assets on the balance sheet:
|
||||||||||||||||
|
Reserve
for injuries and damages
|
||||||||||||||||
|
2006
|
$
|
6,328,361
|
$
|
6,734,385
|
$
|
400,895
|
$
|
4,434,867
|
$
|
9,028,774
|
||||||
|
2005
|
8,121,122
|
6,038,014
|
-
|
7,830,775
|
6,328,361
|
|||||||||||
|
2004
|
8,980,495
|
6,694,152
|
-
|
7,553,525
|
8,121,122
|
|||||||||||
|
|
||||||||||||||||
|
SCE&G:
|
||||||||||||||||
|
Reserves
deducted from related assets on the balance sheet:
|
||||||||||||||||
|
Uncollectible
accounts
|
||||||||||||||||
|
2006
|
$
|
1,574,069
|
$
|
7,481,886
|
-
|
$
|
3,854,788
|
$
|
5,201,167
|
|||||||
|
2005
|
1,182,064
|
3,518,845
|
-
|
3,126,840
|
1,574,069
|
|||||||||||
|
2004
|
951,176
|
2,891,370
|
-
|
2,660,482
|
1,182,064
|
|||||||||||
|
|
||||||||||||||||
|
Reserves
other than those deducted from assets on the balance sheet:
|
||||||||||||||||
|
Reserve
for injuries and damages
|
||||||||||||||||
|
2006
|
$
|
4,892,076
|
$
|
5,980,520
|
-
|
$
|
3,964,279
|
$
|
6,908,317
|
|||||||
|
2005
|
5,749,088
|
3,378,138
|
-
|
4,235,150
|
4,892,076
|
|||||||||||
|
2004
|
6,339,466
|
4,300,548
|
-
|
4,890,926
|
5,749,088
|
|||||||||||
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized. The signature of the undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
|
|
SCANA
CORPORATION
|
|
|
|
BY:
|
/s/W.
B. Timmerman
W.
B. Timmerman, Chairman of the Board,
President,
Chief Executive Officer and Director
|
|
|
DATE:
|
March
1, 2007
|
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 registrant and in the
capacities and on the dates indicated. The signatures of the undersigned shall
be deemed to relate only to matters having reference to the registrant and
any
subsidiaries thereof.
|
|
/s/W.
B. Timmerman
W.
B. Timmerman, Chairman of the Board,
President,
Chief Executive Officer and Director (Principal Executive
Officer)
|
|
|
/s/J.
E. Addison
J.
E. Addison, Senior Vice President
and
Chief Financial Officer
(Principal
Financial Officer)
|
|
|
/s/J.
E. Swan, IV
J.
E. Swan, IV, Controller
(Principal
Accounting Officer)
|
|
Other
Directors*:
|
||||
|
|
B.
L. Amick
|
|
W.
M. Hipp
|
|
|
|
J.
A. Bennett
|
|
L.
M. Miller
|
|
|
|
W.
C. Burkhardt
|
|
M.
K. Sloan
|
|
|
|
S.
A. Decker
|
|
H.
C. Stowe
|
|
|
|
D.
M. Hagood
|
|
G.
S. York
|
|
*Signed
on behalf of each of these persons by Jimmy E. Addison,
Attorney-in-Fact
|
DATE:
|
March
1, 2007
|
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized. The signature of the undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries or consolidated affiliates thereof.
|
|
SOUTH
CAROLINA ELECTRIC & GAS COMPANY
|
|
|
|
BY:
|
/s/K.
B. Marsh
K.
B. Marsh
President
and Chief Operating Officer
|
|
|
DATE:
|
March
1, 2007
|
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 registrant and in the
capacities and on the dates indicated. The signatures of the undersigned shall
be deemed to relate only to matters having reference to the registrant and
any
subsidiaries or consolidated affiliates thereof.
|
|
|
/s/W.
B. Timmerman
W.
B. Timmerman, Chairman of the Board,
Chief
Executive Officer and Director
(Principal
Executive Officer)
|
|
|
|
/s/J.
E. Addison
J.
E. Addison, Senior Vice President
and
Chief Financial Officer
(Principal
Financial Officer)
|
|
|
|
/s/J.
E. Swan, IV
J.
E. Swan, IV, Controller
(Principal
Accounting Officer)
|
|
Other
Directors*:
|
||||
|
|
B.
L. Amick
|
|
W.
M. Hipp
|
|
|
|
J.
A. Bennett
|
|
L.
M. Miller
|
|
|
|
W.
C. Burkhardt
|
|
M.
K. Sloan
|
|
|
|
S.
A. Decker
|
|
H.
C. Stowe
|
|
|
|
D.
M. Hagood
|
|
G.
S. York
|
|
*
Signed
on behalf of each of these persons by Jimmy E. Addison,
Attorney-in-Fact
|
DATE:
|
March
1, 2007
|
|
|
Applicable
to
Form 10-K of
|
|
||||
|
Exhibit
No.
|
SCANA
|
SCE&G
|
Description
|
|||
|
|
|
|
|
|||
|
3.01
|
X
|
Restated
Articles of Incorporation of SCANA Corporation as adopted on
April 26, 1989 (Filed as Exhibit 3-A to Registration Statement
No. 33-49145 and incorporated by reference herein)
|
||||
|
3.02
|
X
|
Articles
of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to
Registration Statement No. 33-62421 and incorporated by reference
herein)
|
||||
|
3.03
|
X
|
Restated
Articles of Incorporation of South Carolina Electric & Gas
Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to
Registration Statement No. 333-65460 and incorporated by reference
herein)
|
||||
|
3.04
|
X
|
Articles
of Amendment effective as of the dates indicated below and filed
as
exhibits to the Registration Statements or Exchange Act reports
set forth
below and are incorporated by reference herein
|
||||
|
|
May 22,
2001
|
Exhibit 3.02
|
to
Registration No. 333-65460
|
|||
|
|
June 14,
2001
|
Exhibit 3.04
|
to
Registration No. 333-65460
|
|||
|
|
August 30,
2001
|
Exhibit 3.05
|
to
Registration No. 333-101449
|
|||
|
|
March 13,
2002
|
Exhibit 3.06
|
to
Registration No. 333-101449
|
|||
|
|
May 9,
2002
|
Exhibit 3.07
|
to
Registration No. 333-101449
|
|||
|
|
June 4,
2002
|
Exhibit 3.08
|
to
Registration No. 333-101449
|
|||
|
|
August 12,
2002
|
Exhibit 3.09
|
to
Registration No. 333-101449
|
|||
|
|
March 13,
2003
|
Exhibit 3.03
|
to
Registration No. 333-108760
|
|||
|
|
May 22,
2003
|
Exhibit 3.04
|
to
Registration No. 333-108760
|
|||
|
|
June 18,
2003
|
Exhibit 3.05
|
to
Registration No. 333-108760
|
|||
|
|
August 7,
2003
|
Exhibit 3.06
|
to
Registration No. 333-108760
|
|||
|
February
26, 2004
|
Exhibit
3.05
|
to
Form 10-K for the year ended December 31, 2004
|
||||
|
|
May 18,
2004
|
Exhibit 3.05
|
to
Form 10-Q for the quarter ended June 30, 2004
|
|||
|
|
June 18,
2004
|
Exhibit 3.06
|
to
Form 10-Q for the quarter ended June 30, 2004
|
|||
|
|
August 12,
2004
|
Exhibit 3.05
|
to
Form 10-Q for the quarter ended Sept. 30,
2004
|
|||
|
|
March
9, 2005
|
Exhibit
3.11
|
to
Form 10-Q for the quarter ended Sept. 30,
2005
|
|||
|
|
May
16, 2005
|
Exhibit
3.12
|
to
Form 10-Q for the quarter ended Sept. 30,
2005
|
|||
|
|
June
15, 2005
|
Exhibit
3.13
|
to
Form 10-Q for the quarter ended Sept. 30,
2005
|
|||
|
|
August
16, 2005
|
Exhibit
3.14
|
to
Form 10-Q for the quarter ended Sept. 30,
2005
|
|||
|
March
14, 2006
|
Exhibit
3.01
|
to
Form 8-K dated March 17, 2006
|
||||
|
May
11, 2006
|
Exhibit
3.01
|
to
Form 8-K filed May 15, 2006
|
||||
|
June
28, 2006
|
Exhibit
3.01
|
to
Form 8-K filed June 29, 2006
|
||||
|
August
16, 2006
|
Exhibit
3.01
|
to
Form 8-K filed August 17, 2006
|
||||
|
|
|
|
|
|||
|
3.05
|
X
|
Articles
of Correction filed on June 1, 2001 correcting May 22, 2001
Articles of Amendment (Filed as Exhibit 3.03 to Registration
Statement No. 333-65460 and incorporated by reference
herein)
|
||||
|
3.06
|
X
|
Articles
of Correction filed on February 17, 2004 correcting Articles of
Amendment for the dates indicated below and filed as exhibits to
the 2003
Form 10-K as set forth below and are incorporated by reference
herein
|
||||
|
|
May 3,
2001
|
Exhibit 3.06
|
|
|||
|
|
May 22,
2001
|
Exhibit 3.07
|
|
|||
|
|
June 14,
2001
|
Exhibit 3.08
|
|
|||
|
|
August 30,
2001
|
Exhibit 3.09
|
|
|||
|
March 13,
2002
|
Exhibit 3.10
|
|||||
|
May 9,
2002
|
Exhibit 3.11
|
|||||
|
June 4,
2002
|
Exhibit 3.12
|
|||||
|
|
August 12,
2002
|
Exhibit 3.13
|
|
|||
|
Applicable
to
Form 10-K
of
|
|||||
|
Exhibit
No.
|
SCANA
|
SCE&G
|
Description
|
||
|
|
|
|
March 13,
2003
|
Exhibit 3.14
|
|
|
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May 22,
2003
|
Exhibit 3.15
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June 18,
2003
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Exhibit 3.16
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August 7,
2003
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Exhibit 3.17
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3.07
|
X
|
Articles
of Correction dated March 17, 2006, correcting March 14, 2006 Articles
of
Amendment (Filed as Exhibit 3.02 to Form 8-K dated March 17, 2006
and
incorporated by reference herein)
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|||
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3.08
|
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X
|
Articles
of Correction dated September 6, 2006, correcting August 16, 2006
Articles
of Amendment (Filed as Exhibit 3.01 to Form 8-K filed September
7, 2006
and incorporated by reference herein)
|
||
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3.09
|
X
|
By-Laws
of SCANA as revised and amended on December 13, 2000 (Filed as
Exhibit 3.01 to Registration Statement No. 333-68266
and
incorporated by reference herein)
|
|||
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3.10
|
X
|
By-Laws
of SCE&G as revised and amended on February 22, 2001 (Filed as
Exhibit 3.05 to Registration Statement No. 333-65460 and
incorporated by reference herein)
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|||
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4.01
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X
|
X
|
Articles
of Exchange of South Carolina Electric & Gas Company and SCANA
Corporation (Filed as Exhibit 4-A to Post-Effective Amendment
No. 1 to Registration Statement No. 2-90438 and incorporated by
reference herein)
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||
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4.02
|
X
|
Indenture
dated as of November 1, 1989 between SCANA Corporation and The Bank
of New York, as Trustee (Filed as Exhibit 4-A to Registration
No. 33-32107 and incorporated by reference herein)
|
|||
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4.03
|
X
|
X
|
Indenture
dated as of April 1, 1993 from South Carolina Electric & Gas
Company to NationsBank of Georgia, National Association (Filed
as
Exhibit 4-F to Registration Statement No. 33-49421 and
incorporated by reference herein)
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||
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4.04
|
X
|
X
|
First
Supplemental Indenture to Indenture referred to in Exhibit 4.03 dated
as of June 1, 1993 (Filed as Exhibit 4-G to Registration
Statement No. 33-49421 and incorporated by reference
herein)
|
||
|
4.05
|
X
|
X
|
Second
Supplemental Indenture to Indenture referred to in Exhibit 4.03 dated
as of June 15, 1993
(Filed
as Exhibit 4-G to Registration Statement No. 33-57955 and
incorporated by reference herein)
|
||
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*10.01
|
X
|
X
|
SCANA
Executive Deferred Compensation Plan as amended February 20, 2003
(filed
as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003
and
incorporated by reference herein)
|
||
|
*10.02
|
X
|
X
|
Amendment
to SCANA Executive Deferred Compensation Plan as adopted December
20, 2005
(Filed as Exhibit 10.02 to Form 10-Q for the quarter ended
March 31, 2006 and incorporated by reference
herein)
|
||
|
*10.03
|
X
|
X
|
Amendments
to SCANA Executive Deferred Compensation Plan as adopted on November
1,
2006 (Filed herewith)
|
||
|
*10.04
|
X
|
X
|
SCANA
Director Compensation and Deferral Plan as amended January 1, 2001
(Filed
as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated
by reference herein)
|
||
|
|
Applicable
to
Form
10-K of
|
|
|
|
Exhibit
No.
|
SCANA
|
SCE&G
|
Description
|
|
*10.05
|
X
|
X
|
Amendment
to SCANA Director Compensation and Deferral Plan as adopted December
20,
2005 (Filed as Exhibit 10.01 to Form 10-Q for the quarter ended March
31, 2006 and incorporated by reference herein)
|
|
*10.06
|
X
|
X
|
Amendments
to SCANA Director Compensation and Deferral Plan as adopted on November
1,
2006 (Filed herewith)
|
|
*10.07
|
X
|
X
|
SCANA
Supplemental Executive Retirement Plan as amended and restated as
of
July 1, 2000 (Filed as Exhibit 10.04 to Form 10-Q for the
quarter ended September 30, 2006 and incorporated by reference
herein)
|
|
*10.08
|
X
|
X
|
Amendments
to the SCANA Supplemental Executive Retirement Plan as adopted on
November
1, 2006 (Filed herewith)
|
|
*10.09
|
X
|
X
|
SCANA
Key Executive Severance Benefits Plan as amended and restated as
of
July 1, 2001 (Filed as Exhibit 10.05 to Form 10-Q for the
quarter ended September 30, 2006 and incorporated by reference
herein)
|
|
*10.10
|
X
|
X
|
Amendments
to the SCANA Key Executive Severance Benefits Plan as adopted on
November
1, 2006 (Filed herewith)
|
|
*10.11
|
X
|
X
|
SCANA
Supplementary Key Executive Severance Benefits Plan as amended and
restated as of July 1, 2001 (Filed as Exhibit 10.06 to
Form 10-Q for the quarter ended September 30, 2006 and
incorporated by reference herein)
|
|
*10.12
|
X
|
X
|
Amendments
to the SCANA Supplementary Key Executive Severance Benefits Plan
as
adopted on November 1, 2006 (Filed herewith)
|
|
*10.13
|
X
|
X
|
SCANA
Executive Benefit Plan as established effective as of July 1, 2001
(Filed
herewith)
|
|
*10.14
|
X
|
X
|
Amendments
to the SCANA Executive Benefit Plan as adopted on November 1, 2006
(Filed
herewith)
|
|
*10.15
|
X
|
X
|
SCANA
Supplementary Executive Benefit Plan as established effective as
of July
1, 2001 (Filed herewith)
|
|
*10.16
|
X
|
X
|
Amendments
to the SCANA Supplementary Executive Benefit Plan as adopted on November
1, 2006 (filed herewith)
|
|
*10.17
|
X
|
X
|
SCANA
Long-Term Equity Compensation Plan as amended and restated as of
January
1, 2005 (Filed as Exhibit 10.01 to Form 8-K dated May 5, 2005 and
incorporated by reference herein)
|
|
*10.18
|
X
|
X
|
Description
of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended
December 31, 1991, under cover of Form SE, Filed No. 1-8809 and
incorporated by reference herein)
|
|
*10.19
|
X
|
X
|
SCANA
Short-Term Annual Incentive Plan as amended and restated effective
January
1, 2005 (Filed as Exhibit 10.10 to Form 10-Q for the quarter ended
September 30, 2005 and incorporated by reference
herein)
|
|
*10.20
|
X
|
X
|
Amendments
to SCANA Short-Term Annual Incentive Plan as adopted on November
1, 2006
(Filed herewith)
|
|
10.21
|
X
|
Service
Agreement between SCE&G and SCANA Services, Inc., effective
January 1, 2004 (Filed as Exhibit 10.16 to Form 10-Q for
the quarter ended March 31, 2004 and incorporated by reference
herein)
|
|
|
Applicable
to
Form 10-K
of
|
|||
|
Exhibit
No.
|
SCANA
|
SCE&G
|
Description
|
|
*10.22
|
X
|
Independent
contractor agreement with Neville O. Lorick (Filed as Exhibit 99.1
to Form
8-K filed
June
15, 2006 and incorporated by reference herein)
|
|
|
12.01
|
X
|
Statement
Re Computation of Ratios
|
|
|
12.02
|
X
|
Statement
Re Computation of Ratios
|
|
|
21.01
|
X
|
Subsidiaries
of the registrant (Filed herewith under the heading “Corporate Structure”
in Part I, Item I
of
this Form 10-K and incorporated by reference
herein)
|
|
|
23.01
|
X
|
Consents
of Experts and Counsel (Consent of Independent Registered Public
Accounting Firm)
|
|
|
23.02
|
X
|
Consents
of Experts and Counsel (Consent of Independent Registered Public
Accounting Firm)
|
|
|
24.01
|
X
|
X
|
Power
of Attorney (Filed herewith)
|
|
31.01
|
X
|
Certification
of Principal Executive Officer Required by Rule 13a-14 (Filed
herewith)
|
|
|
31.02
|
X
|
Certification
of Principal Financial Officer Required by Rule 13a-14 (Filed
herewith)
|
|
|
31.03
|
X
|
Certification
of Principal Executive Officer Required by Rule 13a-14 (Filed
herewith)
|
|
|
31.04
|
X
|
Certification
of Principal Financial Officer Required by Rule 13a-14 (Filed
herewith)
|
|
|
32.01
|
X
|
Certification
of Principal Executive Officer Pursuant to 18 U.S.C.
Section 1350 (Furnished herewith)
|
|
|
32.02
|
X
|
Certification
of Principal Financial Officer Pursuant to 18 U.S.C.
Section 1350 (Furnished herewith)
|
|
|
32.03
|
X
|
Certification
of Principal Executive Officer Pursuant to 18 U.S.C.
Section 1350 (Furnished herewith)
|
|
|
32.04
|
X
|
Certification
of Principal Financial Officer Pursuant to 18 U.S.C.
Section 1350 (Furnished
herewith)
|
|
*
Management Contract or Compensatory Plan or Arrangement