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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2001
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-3375 South Carolina Electric & Gas Company 57-0248695
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-11429 Public Service Company of North Carolina, Incorporated 56-2128483
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
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.
Title of each class Registrant
Common Stock, without par value SCANA Corporation
5% Cumulative Preferred Stock South Carolina Electric & Gas Company
par value $50 per share
7.55% Trust Preferred Securities, South Carolina Electric & Gas Company
Series A liquidation value $25 per
Trust Preferred Security
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Securities registered pursuant to Section 12(g) of the Act: None
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)
Public Service Company of North Carolina, Incorporated (x)
The aggregate market value of voting stock held by non-affiliates of
SCANA Corporation was $2.9 billion at February 28, 2002, based on a price of
$27.75. Each of the other registrants 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:
Shares Outstanding
Registrant Description of Common Stock
- ---------- --------------------------- --------------------
SCANA Corporation Without Par Value 104,728,268
South Carolina Electric
and Gas Company $4.50 Par Value 40,296,147
Public Service Company
of North Carolina,Incorporated Without Par Value 1,000
Documents incorporated by reference: Specified sections of SCANA
Corporation's 2002 Proxy Statement, dated March 22, 2002, in connection with its
2002 Annual Meeting of Shareholders, are incorporated by reference in Part III
hereof.
This combined Form 10-K is separately filed by SCANA Corporation, South Carolina
Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. 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 companies.
Public Service Company of North Carolina, Incorporated meets the conditions set
forth in General Instruction I (1) (a) and (b) of Form 10-K and therefore is
filing this form with the reduced disclosure format allowed under General
Instruction I (2).
TABLE OF CONTENTS
Page
DEFINITIONS.............................................................. 4
PART I
Item 1. Business................................................... 5
Item 2. Properties ................................................ 18
Item 3. Legal Proceedings.......................................... 20
Item 4. Submission of Matters to a Vote of Security Holders ....... 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Shareholder Matters...................................... 21
Item 6. Selected Financial Data.................................... 22
SCANA Corporation.......................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
South Carolina Electric & Gas Company....................... 80
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Public Service Company of North Carolina, Incorporated...... 118
Item 7. Management's Narrative Analysis of Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure...................................... 148
PART III
Item 10. Directors and Executive Officers of the Registrants......... 148
Item 11. Executive Compensation ..................................... 153
Item 12. Security Ownership of Certain Beneficial Owners
and Management ........................................... 158
Item 13. Certain Relationships and Related Transactions ............. 159
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K ................................................. 160
SIGNATURES................................................................ 164
DEFINITIONS
The following abbreviations used in the text have the meanings set forth below
unless the context requires otherwise:
TERM MEANING
AFC..................................... Allowance for Funds Used During C
Construction
BTU..................................... British Thermal Unit
Circuit Court........................... South Carolina Circuit Court
Consumer Advocate....................... Consumer Advocate of South Carolina
DHEC.................................... South Carolina Department of Health
and Environmental Control
DOE..................................... United States Department of Energy
DT...................................... Dekatherm (one million BTU's)
DTAG.................................... Deutsche Telekom AG
Energy Marketing........................ SCANA Energy Marketing, Inc.
EPA..................................... United States Environmental Protection
Agency
FERC.................................... United States Federal Energy
Regulatory Commission
Fuel Company............................ South Carolina Fuel Company, Inc.
GENCO................................... South Carolina Generating Company, Inc.
GPSC.................................... Georgia Public Service Commission
Investor Plus Plan...................... SCANA Corporation Investor Plus Plan
KVA..................................... Kilovolt-ampere
KW...................................... Kilowatt
KWH..................................... Kilowatt-hour
LLC..................................... Limited Liability Company
LNG..................................... Liquefied Natural Gas
MCF..................................... Thousand Cubic Feet
MGP..................................... Manufactured Gas Plant
Mhz..................................... Megahertz
MMBTU................................... Million British Thermal Units
MMCF.................................... Million Cubic Feet
MW...................................... Megawatt
NCUC.................................... North Carolina Utilities Commission
NRC..................................... United States Nuclear Regulatory
Commission
PRP..................................... Potentially Responsible Party
PSNC.................................... Public Service Company of North
Carolina, Incorporated
PUHCA................................... Public Utility Holding Company Act of
1935, as amended
RTO..................................... Regional Transmission Organization
Santee Cooper........................... South Carolina Public Service Authority
SCANA................................... SCANA Corporation, the parent company
SCE&G................................... South Carolina Electric & Gas Company
SCH..................................... SCANA Communications Holdings, Inc., a
subsidiary of SCI
SCI..................................... SCANA Communications, Inc.
SCPC.................................... South Carolina Pipeline Corporation
SCPSC................................... The Public Service Commission of South
Carolina
SEC..................................... United States Securities and Exchange
Commission
SFAS.................................... Statement of Financial Accounting
Standards
Southern Natural........................ Southern Natural Gas Company
SPSP.................................... SCANA Corporation Stock Purchase-
Savings Plan
Summer Station.......................... V. C. Summer Nuclear Station
Supreme Court........................... South Carolina Supreme Court
Transco................................. Transcontinental Gas Pipeline
Corporation
Williams Station........................ A. M. Williams Coal-Fired, Electric
Generating Station Owned by GENCO
WNA..................................... Weather Normalization Adjustment
PART I
ITEM 1. BUSINESS
CORPORATE STRUCTURE
SCANA CORPORATION
A holding company owning the direct, wholly owned subsidiaries listed below
SOUTH CAROLINA ELECTRIC & GAS COMPANY SCANA COMMUNICATIONS, INC.
- -------------------------- --------------------------
Provides fiber optic telecommunications
Generates and sells electricity and gas in South Carolina, tower construction,
to wholesale and retail customers; management and rental services for wireless
purchases, sells and transports natural gas providers and, through a Delaware subsidiary,
at retail and provides public transit invests in telecommunications companies.
service in Columbia, South Carolina.
SCANA ENERGY MARKETING, INC.
SOUTH CAROLINA GENERATING COMPANY, INC. Markets natural gas and wholesale electricity
primarily in the Southeast. Provides energy-
Owns and operates Williams Station and related risk management services to producers
sells electricity to SCE&G. and customers. Through its SCANA Energy
division, markets natural gas in Georgia's
SOUTH CAROLINA FUEL deregulated retail
natural gas market.
COMPANY, INC.
Acquires, owns and provides financing SERVICECARE, INC.
-----------------
for SCE&G's nuclear fuel, fossil fuel Provides energy-related products and
and sulfur dioxide emission allowances. service contracts on home appliances.
SOUTH CAROLINA PIPELINE PRIMESOUTH, INC.
- ------------------------ ----------------
CORPORATION Engages in power plant management and
- -----------
Purchases, sells and transports natural maintenance services.
gas to wholesale and direct industrial
customers. Owns and operates two LNG SCANA RESOURCES, INC.
---------------------
plants for the liquefaction, storage and Conducts energy-related businesses and provides
regasification of natural gas. energy-related services.
PUBLIC SERVICE COMPANY OF SCG PIPELINE, INC.
- ------------------------- ------------------
NORTH CAROLINA, INCORPORATED Organized to engage in the transportation of
- ----------------------------
Purchases, sells, transports and distributes natural gas in Georgia and South Carolina.
natural gas to retail customers, markets
natural gas, refuels natural gas vehicles and SCANA SERVICES, INC.
--------------------
converts gasoline-fueled vehicles to Provides administrative, management and other
natural gas. services to the subsidiaries and business units
within SCANA Corporation.
Each of the above listed companies is organized and incorporated under the
laws of the State of South Carolina. SCANA also owns four additional
companies that are in liquidation.
ORGANIZATION
SCANA, a South Carolina corporation having general business powers, was
incorporated on October 10, 1984, and registered as a public utility holding
company under PUHCA on February 10, 2000. SCANA holds, directly or indirectly,
all of the capital stock of each of its subsidiaries except for the preferred
stock of SCE&G, the preferred securities of SCE&G Trust I and 30 percent of an
indirect subsidiary in liquidation. SCANA and its subsidiaries (the Company) had
full-time, permanent employees as of February 28, 2002 and 2001 of 5,369 and
5,262, respectively. SCE&G was incorporated under the laws of South Carolina in
1924, and is an operating public utility. SCE&G had full-time, permanent
employees as of February 28, 2002 and 2001 of 2,657 and 2,365, respectively.
Prior to being acquired by SCANA in 2000, PSNC was incorporated under the laws
of North Carolina in 1938. PSNC is now incorporated under the laws of South
Carolina. PSNC, doing business as PSNC Energy, is an operating public utility in
North Carolina with full-time, permanent employees as of February 28, 2002 and
2001 of 652 and 653, respectively.
SEGMENTS OF BUSINESS
SCANA neither owns nor operates any physical properties. It has 12
direct, wholly owned subsidiaries that are engaged in the functionally distinct
operations described below, and an investment in ITC^DeltaCom, Inc., a
telecommunications services company in the southeastern United States. SCANA
also has investments in two LLCs: one owns and operates a cogeneration facility
in Charleston, South Carolina and the other owns and operates a lime production
facility in Charleston, South Carolina. Effective February 28, 2002 SCANA sold
its interest in the lime production facility. SCANA also has four other direct,
wholly owned subsidiaries that are in liquidation.
Information with respect to major segments of business for the years
ended December 31, 2001, 2000 and 1999 is contained in Management's Discussion
and Analysis of Financial Condition and Results of Operations for SCANA and
SCE&G and the Notes to Consolidated Financial Statements appearing in Item 8,
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 14), SCE&G (Note 13)
and PSNC (Note 13). All such information is incorporated herein by reference.
Regulated Utilities
SCE&G 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 in South Carolina. SCE&G also renders urban
bus service in the metropolitan area of Columbia, South Carolina. In November
2001 SCE&G signed a letter of intent to transfer the transit system to an
unaffiliated regional transit authority (see discussion at Item 2, PROPERTIES -
TRANSIT PROPERTIES). 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 area extends into 24 counties covering more than 15,000 square miles in
the central, southern and southwestern portions of South Carolina. The service
area for natural gas encompasses all or part of 33 of the 46 counties in South
Carolina and covers more than 22,000 square miles. The total population of the
counties representing the combined service area is approximately 2.6 million.
Predominant industries in the areas 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 and operates 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 sulfur dioxide emission allowance requirements.
SCPC is engaged in the purchase, transmission and sale of natural gas on
a wholesale basis to distribution companies and directly to industrial customers
in 40 counties throughout South Carolina. SCPC owns LNG liquefaction and storage
facilities. It also supplies the natural gas for SCE&G's gas distribution
system. Other resale customers include municipalities and county gas authorities
and gas utilities. The industrial customers of SCPC are primarily engaged in the
manufacturing or processing of ceramics, paper, metal, food and textiles.
SCPC's plan to convert from a closed system to an open access
transportation only system has been postponed indefinitely due to a number of
factors, including the impact of the current economic downturn and the lack of
consistent customer support for the proposed plan of system conversion.
PSNC is a public utility engaged primarily in purchasing, selling,
transporting and distributing natural gas to approximately 379,000 residential,
commercial and industrial customers. PSNC provides service to 26 of its 28
franchised counties covering approximately 12,000 square miles in North
Carolina. The industrial customers of PSNC include manufacturers or processors
of textiles, chemicals, ceramics and clay products, glass, automotive products,
minerals, pharmaceuticals, plastics, metals, electronic equipment, furniture and
a variety of food and tobacco products. PSNC, through a wholly owned,
nonregulated subsidiary, refuels natural gas vehicles and converts
gasoline-fueled vehicles to natural gas. Effective January 1, 2001, PSNC's gas
brokering activities were transferred to Energy Marketing.
Nonregulated Businesses
Energy Marketing markets natural gas and wholesale electricity primarily
in the southeast. Energy Marketing also provides energy-related risk management
services to producers and customers. In addition, SCANA Energy, a division of
Energy Marketing, markets natural gas to approximately 385,000 customers (as of
December 31, 2001) in Georgia's deregulated natural gas market.
SCI owns and operates a 500-mile fiber optic telecommunications network
in South Carolina and provides tower site construction, management and rental
services in South Carolina and Georgia. SCI also owns an 800 Mhz radio service
network within South Carolina, and in June 2001, agreed to subcontract the
operation and maintenance of its network to Motorola, Inc. (Motorola) for the
period July 1, 2001 through March 31, 2002. SCI intends to sell the network to
Motorola at a purchase price in excess of its carrying value.
SCH, a Delaware corporation and a wholly owned subsidiary of SCI, has
investments in ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology, Inc.,
which are telecommunications services companies in the southeastern United
States. SCH also has an investment in Deutsche Telekom AG (DTAG), an
international telecommunications carrier. This investment was received in
exchange for its Powertel, Inc. (Powertel) investment owned prior to DTAG's
acquisition of Powertel in May 2001.
ServiceCare, Inc. (ServiceCare) is engaged primarily in providing
homeowners with service contracts on their home appliances. In March 2001
ServiceCare completed the sale of its home security and alarm monitoring
division.
SCG Pipeline, Inc. (SCG), when operational, will provide interstate
transportation services for natural gas to markets in southeastern Georgia and
South Carolina. SCG will transport natural gas from interconnections with
Southern Natural at Port Wentworth, Georgia, and from an import terminal owned
by Southern LNG at Elba Island, near Savannah, Georgia. The endpoint of SCG's
line will be at the site of SCE&G's proposed natural gas-fired generating
station in Jasper County, South Carolina. In December 2001 SCG filed an
application with FERC for a Certificate of Public Convenience and Necessity to
acquire and build a pipeline from Elba Island, Georgia to Jasper County, South
Carolina. The project has an anticipated in-service date of November 2003.
Primesouth, Inc. is engaged primarily in power plant management and
maintenance services. Primesouth is also involved in the operation of an
alternate fuel facility owned by non-affiliates, and it receives management fees
and expense reimbursement related to those activities.
SCANA Resources, Inc. conducts energy-related businesses and provides
energy-related services.
Service Company
SCANA Services, Inc. provides administrative, management and other services
to the subsidiaries and business units within the Company.
COMPETITION
For a discussion of the impact of competition, see the Competition
section of Management's Discussion and Analysis of Financial Condition and
Results of Operations for SCANA and SCE&G, and the Competition section of
Management's Narrative Analysis of Results of Operations for PSNC.
CAPITAL REQUIREMENTS
The Company's cash requirements arise primarily from the operational
needs of SCANA's subsidiaries, the Company's construction program and payment of
dividends. The ability of SCANA's regulated subsidiaries to replace existing
plant investment, as well as to expand to meet future demand for electricity and
gas, will depend upon their ability to attract the necessary financial capital
on reasonable terms. SCANA's 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 the regulated subsidiaries continue their ongoing
construction programs, the Company expects to seek increases in rates. The
Company's future financial position and results of operations will be affected
by the regulated subsidiaries' ability to obtain adequate and timely rate and
other regulatory relief, if requested.
For a discussion of the impact of various rate matters on the Company's
capital requirements, see the Regulatory Matters captions in the Liquidity and
Capital Resources section of Management's Discussion and Analysis of Financial
Condition and Results of Operations for SCANA and SCE&G and the Notes to
Consolidated Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA for SCANA (Note 4), SCE&G (Note 3) and PSNC (Note 5).
During the three-year period 2002-2004, the Company expects to meet its
capital requirements principally through internally generated funds
(approximately 45 percent, after payment of dividends) and the incurrence of
additional short-term and long-term indebtedness. Sales of additional equity
securities may also occur. The Company expects that it has or can obtain
adequate sources of financing to meet its projected cash requirements for the
next 12 months and for the foreseeable future.
The Company's current estimates of its cash requirements for construction
and nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 2002-2004 are as follows:
- ---------------------------------------------------- -------------- ------------
Type of Facilities 2004 2003 2002
- ------------------ ---- ---- ----
(Millions of Dollars)
South Carolina Electric & Gas Company:
Electric Plant:
Generation $134 $362 $328
Transmission 37 41 33
Distribution 108 101 96
Other 9 12 15
Nuclear Fuel 26 29 6
Gas 20 18 19
Common 15 23 13
Other - - 2
- ---------------------------------------------------- -------------- ------------
Total SCE&G 349 586 512
PSNC 38 37 40
Other Companies Combined 44 150 131
- ---------------------------------------------------- -------------- ------------
Total $431 $773 $683
- ---------------------------------------------------- -------------- ------------
In October 1999 FERC notified SCE&G of its agreement with SCE&G's plan to
reinforce Lake Murray Dam in order to maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001, is expected to cost $250 million and be completed in
2005. Any costs incurred by SCE&G are expected to be recoverable through
electric rates.
SCE&G is constructing a $256 million gas turbine generator project in
Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas
to produce 300 megawatts of new electric generation and use exhaust heat to
replace coal-fired steam that powers two existing 75 megawatt turbines at the
Urquhart Generating Station. The turbine project is scheduled to be completed by
June 2002.
In October 2001 SCE&G filed with the SCPSC its siting plans to construct
an 875 megawatt generation facility in Jasper County, South Carolina, to supply
electricity primarily to its South Carolina customers. The facility will include
three natural gas combustion-turbine generators and one steam-turbine generator.
Natural gas will be provided by SCG Pipeline, Inc. Construction of the $450
million facility is expected to begin in April 2002, with commercial operation
in the summer of 2004. In connection with the facility, SCE&G has signed a 250
megawatt electric supply contract with North Carolina Electric Membership
Corporation for a term of at least five years beginning January 1, 2004.
In addition to the capital requirements for 2002 described above, the
Company, SCE&G and PSNC will require approximately $738.3 million, $27.6 million
and $4.3 million, respectively, to refund and retire outstanding long-term
securities and obligations in 2002 including purchase or sinking fund
requirements for SCE&G's preferred stock. For the years 2003-2006, the Company
has an aggregate of $1,034.3 million of long-term debt and preferred stock
maturing, which includes an aggregate of $576.3 million for SCE&G, $2.2 million
of purchase or sinking fund requirements for SCE&G's preferred stock and $21.4
million for PSNC. SCE&G's long-term debt maturities for the years 2003-2006
include approximately $93.8 million for sinking fund requirements, all of which
may be satisfied by deposit and cancellation of bonds issued upon the basis of
property additions or bond retirement credits.
For a discussion of the Company's, SCE&G's and PSNC's 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 and the Capital Expansion Program and Liquidity Matters section
of Management's Narrative Analysis of Results of Operations for PSNC.
The Company's ratios of earnings to fixed charges were 4.37, 2.47, 2.77,
3.38 and 3.27 for the years ended December 31, 2001, 2000, 1999, 1998 and 1997,
respectively. For SCE&G these ratios were 3.78, 4.24, 3.71, 4.40 and 3.85 for
the same periods. For PSNC these ratios were 2.54 and 3.05 for the years ended
December 31, 2001 and 2000, respectively, and 3.18, 3.22 and 3.41 for its fiscal
years ended September 30, 1999, 1998 and 1997, respectively.
The Company has set a target ratio of debt to total capital of 50 to 52
percent. At December 31, 2001, the ratio of debt to total capital was
approximately 59 percent.
ELECTRIC OPERATIONS
Electric Sales
In 2001 residential sales of electricity accounted for 39% of electric
sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 3%;
and all other 9%. The Company's KWH sales by classification for the years ended
December 31, 2001 and 2000, excluding volumes attributable to the cumulative
effect of accounting change in 2000, are presented below:
KWH Sales (in millions)
----------------------------------------------------------------------------
CLASSIFICATION 2001 2000 % CHANGE
----------------------------------------------------------------------------
Residential 6,494 6,665 (3%)
Commercial 6,288 6,305 -
Industrial 6,347 6,665 (5%)
Sales for resale 1,114 1,222 (9%)
Other 534 553 (3%)
--------------------------------------------------------------
Total Territorial 20,777 21,410 (3%)
Negotiated Market Sales Tariff (NMST) 2,151 1,942 11%
--------------------------------------------------------------
Total 22,928 23,352 (1.8%)
==============================================================
Sales for resale includes sales to two municipalities and two electric
cooperatives. Sales under the NMST during 2001 include sales to 39
investor-owned utilities and registered marketers, four electric cooperatives,
two municipalities and four federal/state electric agencies. During 2000 sales
under the NMST included sales to 36 investor-owned utilities and registered
marketers, seven electric cooperatives, two municipalities and four
federal/state electric agencies.
The residential electric sales volume decreased for 2001 primarily as a
result of milder weather. During 2001 the Company recorded a net increase of
10,143 customers, increasing its total customers to 547,388. The all-time peak
demand of 4,196 MW was set on August 8, 2001. The industrial electric sales
volume decreased for 2001 primarily due to the impact of an economic slowdown.
For the three-year period 2002-2004, the Company's total KWH sales of
electricity are projected to increase 2.4% annually. Residential KWH sales are
projected to increase 1.9% annually, commercial sales 1.7%, industrial sales
2.7%, sales for resale 6.6% and other sales 0.9%. The Company's total electric
customer base is projected to increase 1.4% annually. Over the same three-year
period, the Company's territorial peak load (summer, in MW) is projected to
increase 2% annually. The Company's goal is to maintain a reserve margin of
between 12.0% and 18.0%.
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 generating capacity of 580 MW.
SCE&G's transmission system is part of the interconnected grid
extending over a large part of the southern and eastern portions of the nation.
SCE&G, Virginia Electric and Power Company, Duke Power Company, Carolina Power &
Light Company, Yadkin, Incorporated and Santee Cooper are members of the
Virginia-Carolinas Reliability Group, one of several geographic divisions within
the Southeastern Electric Reliability Council. This Council provides for
coordinated planning for reliability among bulk power systems in the Southeast.
SCE&G is also interconnected with Georgia Power Company, Savannah Electric &
Power Company, Oglethorpe Power Corporation and the Southeastern Power
Administration's Clark Hill Project. (See REGULATION - FERC Orders No. 636, 888
and 2000 for further discussion of electric interconnections.)
Fuel Costs
The following table sets forth the average cost of nuclear fuel and
coal and the weighted average cost of all fuels (including oil and natural gas)
used by the Company for the years 1999-2001.
Cost of Fuel Used
-----------------------------------------
2001 2000 1999
---- ---- ----
Nuclear:
Per MMBTU $.45 $.46 $.46
Coal:
SCE&G
Per ton $38.70 $37.10 $39.37
Per MMBTU 1.55 1.48 1.57
GENCO
Per ton $39.23 $38.98 $41.46
Per MMBTU 1.52 1.51 1.61
Weighted Average Cost of All Fuels:
Per MMBTU $1.33 $1.31 $1.32
Fuel Supply
The following table shows the sources and approximate percentages of
the Company's total KWH generation by each category of fuel for the years
1999-2001 and the estimates for the years 2002-2004.
Percent of Total KWH Generated
--------------------------------------------------------------
Estimated Actual
--------------------------------------------------------------
2004 2003 2002 2001 2000 1999
---- ---- ---- ---- ---- ----
Coal 61% 66% 70% 75% 77% 73%
Nuclear 20 20 20 21 18 22
Hydro 5 6 5 4 4 4
Natural Gas & Oil 14 8 5 - 1 1
------------------ -------------------- ----------- ---------
100% 100% 100% 100% 100% 100%
================== ==================== =========== ==========
Coal is used at all five of SCE&G's fossil fuel-fired plants and
GENCO's Williams Station. Unit train deliveries are used at all of these plants.
On December 31, 2001 SCE&G had approximately a 64-day supply of coal in
inventory and GENCO had approximately a 68-day supply.
Coal is obtained through contracts and purchases on the spot market.
Spot market purchases are expected to continue for coal requirements in excess
of those provided by existing contracts.
Contract coal is purchased from twelve suppliers located in eastern
Kentucky, Tennessee, southwest Virginia and West Virginia. Contract commitments,
which expire at various times through 2004, approximate 6.0 million tons
annually, which is 89 percent of total expected coal purchases for 2002. Sulfur
restrictions on the contract coal range from 0.75 percent to 1.5 percent.
As noted above in Capital Requirements, SCE&G is building two
combined-cycle turbines that will burn natural gas to produce 300 megawatts of
new electric generation and use exhaust heat to replace coal-fired steam that
powers two existing 75 megawatt turbines at the Urquhart Generating Station. The
turbine project is scheduled to be completed by June 2002. Also, as part of the
transfer of transit assets discussed at Item 2, PROPERTIES - TRANSIT PROPERTIES,
SCE&G may transfer a small hydro plant to the City of Columbia. This transfer
would have minimal impact on the makeup of SCE&G's fuel supply above.
The Company believes that SCE&G's and GENCO's operations comply with
all existing regulations relating to the discharge of sulfur dioxide and
nitrogen oxides. The Company is unaware of any more stringent sulfur content
requirements for existing plants being contemplated at the state and Federal
level.
SCE&G has adequate supplies of uranium or enriched uranium product
under contract to manufacture nuclear fuel for Summer Station through 2008. The
following table summarizes all contract commitments for the stages of nuclear
fuel assemblies:
Remaining Expiration
Commitment Contractor Regions(1) Date
Enrichment United States Enrichment Corporation (2) 16-20 2008
Fabrication Westinghouse Electric Corporation 16-21 2009
(1) A region represents approximately one-third to one-half of the nuclear
core in the reactor at any one time. Region 15 was loaded in 2001. Region 16
will be loaded in 2002.
(2) Contract provisions for the delivery of enriched uranium product
encompass supply, conversion and enrichment services.
SCE&G has on-site spent nuclear fuel storage capability until at least
2008 and expects to be able to expand its storage capacity to accommodate the
spent fuel output for the life of the plant through spent fuel pool reracking,
dry cask storage or other technology as it becomes available. In addition, there
is sufficient on-site storage capacity over the life of Summer Station to permit
storage of the entire reactor core in the event that complete unloading should
become desirable or necessary. (See Nuclear Fuel Disposal under Environmental
Matters for information regarding the contract with the DOE for disposal of
spent fuel.)
Decommissioning
For information regarding the decommissioning of Summer Station, see
Note 1H, Nuclear Decommissioning, of the Notes to Consolidated Financial
Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for
SCANA and SCE&G.
Other Significant Events
In March 2001 Summer Station returned to service. It had been taken out
of service in October 2000 for a planned maintenance and refueling outage.
During initial inspection activities, plant personnel discovered a small leak in
a weld in a primary coolant system pipe. Repairs were completed and the
integrity of the new welds was verified through extensive testing. The SCPSC has
approved recovery of the cost of replacement power through SCE&G's electric fuel
adjustment clause. The NRC was closely involved throughout this process and
approved SCE&G's actions, as well as the restart schedule.
In April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
returned to service. It had been taken out of service in January 2001 due to an
electrical ground in the generator. The SCPSC has approved recovery of the cost
of replacement power through SCE&G's fuel adjustment clause.
SCANA and Westvaco each own a 50 percent interest in Cogen South LLC
(Cogen). Cogen built and operates a cogeneration facility in North Charleston,
South Carolina. On September 10, 1998 the contractor in charge of construction
filed suit in Circuit Court alleging that it incurred construction cost overruns
relating to the facility and that the construction contract provides for
recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were
named as defendants in the suit. Cogen filed a separate suit against the
contractor for delay and performance issues. The suits were combined and the
contractor brought the manufacturer of the generator into the performance suit.
In November 2001 a settlement was reached between all parties. Terms of the
settlement are confidential, but the settlement's impact on SCANA and SCE&G's
results of operations, cash flow and financial position is not material.
GAS OPERATIONS
For the three-year period 2002-2004, the Company's total consolidated
sales of natural gas in DTs are projected to increase 1.5% annually. Residential
DT sales are projected to increase 2.6% annually, commercial sales 2.7%,
industrial sales 1.0% and sales for resale 0.0%. The Company's total
consolidated natural gas customer base is projected to increase 2.9% annually.
Gas Sales - Regulated
In 2001 the Company's residential sales accounted for 40% of gas sales
revenues; commercial sales 24%; industrial sales 23%; sales for resale 9%; and
other 4%. During the same period, SCE&G's residential sales accounted for 44% of
gas sales revenues; commercial sales 33%; and industrial sales 23%. Also during
the same period, PSNC's residential sales accounted for 59% of gas sales
revenues; commercial sales 27%; and industrial sales 14%. DT sales by
classification for the years ended December 31, 2001 and 2000, excluding volumes
associated with the cumulative effect of accounting change in 2000, are
presented below:
Dekatherms Sales (in thousands)
- -------------------------------------------------------------------------------------------------------------------
The Company SCE&G PSNC
% % %
CLASSIFICATION 2001 2000 Change 2001 2000 Change 2001 2000 Change
- ---------------------------- --------- -------------------- --------- ---------- --------- --------- -----------
Residential 31,966 39,034 (18.1) 11,256 14,506 (22.4) 20,710 24,529 (15.6)
Commercial 23,652 26,306 (10.1) 11,305 12,817 (11.8) 12,278 13,373 (8.2)
Industrial 47,901 61,668 (22.3) 14,301 17,129 (16.5) 5,277 5,315 (0.7)
Sales for Resale 14,827 16,931 (12.4) n/a n/a n/a
n/a n/a n/a
Transportation gas 28,706 31,675 (9.4) 2,461 2,085 18.0 25,719 29,413 (12.6)
------ ------ ----- -- ----- ------ ------
Total 147,052 175,614 (16.3) 39,323 46,537 (15.5) 63,984 72,630 (11.9)
============================ ========= ==================== ========= ========== ========= ========= ===========
The Company's DT sales noted above include SCPC sales of 84,840 DTs and
103,815 DTs, for 2001 and 2000, respectively (including transactions with
affiliates). The Company's and SCE&G's gas sales volume decreased for 2001
primarily as a result of the slowing economy. During 2001 the Company recorded a
net increase of approximately 9,200 customers, increasing its total customers to
approximately 646,200. SCE&G recorded a net increase of approximately 800 gas
customers, increasing its total customers to approximately 267,200. PSNC
recorded a net increase of approximately 8,700 customers, increasing its total
customers to approximately 378,900.
The demand for gas is affected by the weather, the price relationship
between gas and alternate fuels and other factors.
SCPC, operating wholly within the State of South Carolina, provides
natural gas utility and transportation services for its customers, and supplies
natural gas to SCE&G and other wholesale purchasers. Energy Marketing acquires
and sells natural gas in regulated and deregulated markets. Energy Marketing has
not supplied natural gas to any affiliate for use in providing regulated gas
utility services.
Gas Cost, Supply and Curtailment Plans
South Carolina
SCPC 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 (expiring in 2005 and
2006) and Transco (expiring in 2008 and 2017). The daily volume of gas that SCPC
is entitled to transport under these contracts on a firm basis is 188 MMCF from
Southern Natural and 105 MMCF from Transco. Additional natural gas volumes are
brought to SCPC's system as capacity is available for interruptible
transportation. SCE&G, under contract with SCPC, is entitled to receive a daily
contract demand of 276,495 dekatherms. The contract allows SCE&G to receive
amounts in excess of this demand based on availability.
During 2001 SCPC's average cost per MCF of natural gas purchased for
resale, including firm service demand charges, was $5.47 compared to $4.39
during 2000. SCE&G's average cost per MCF was $6.91 and $5.35 during 2001 and
2000, respectively. These increases reflect average natural gas prices during
the three months ended March 31, 2001 that were approximately $4.68 (for SCPC)
and $4.58 (for SCE&G) higher than the three months ended March 31, 2000.
SCPC has engaged in hedging activities on the New York Mercantile
Exchange (NYMEX) of its gas supply pursuant to a limited program authorized and
monitored by the SCPSC. Any gains or losses associated with that hedging
activity are accounted for in SCPC's purchased gas adjustment clause and,
therefore, have no impact on net income.
To meet the requirements of its high priority natural gas customers
during periods of maximum demand, SCPC supplements its supplies of natural gas
from two LNG plants. The LNG plants are capable of storing the liquefied
equivalent of 1,880 MMCF of natural gas. Approximately 1,689 MMCF of gas were in
storage at December 31, 2001. On peak days the LNG plants can regasify up to 150
MMCF per day. Additionally, SCPC had contracted for 6,447 MMCF of natural gas
storage space. Approximately 5,393 MMCF of gas were in storage on December 31,
2001.
The SCPSC has established allocation priorities applicable to the firm
and interruptible capacities of SCPC. These curtailment plan priorities apply to
the resale distribution customers of SCPC, including SCE&G.
North Carolina
PSNC 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. The gas is
brought to North Carolina through transportation agreements with Transco and
Dominion Gas Transmission with expiration dates ranging through 2016. The daily
volume of gas that PSNC is entitled to transport under these contracts on a firm
basis is 259,894 dekatherms from Transco and 30,331 dekatherms from Dominion Gas
Transmission. PSNC has submitted non-binding nominations for firm transportation
service on three proposed pipeline projects to meet incremental capacity
requirements beginning in 2003. At December 31, 2001 evaluation and final
determination regarding subscription to these projects were ongoing.
During 2001 PSNC's average cost per DT of natural gas purchased for
resale, including firm service demand charges, was $6.50 compared to $5.63
during 2000. This increase reflects average natural gas prices during the three
months ended March 31, 2001 that were approximately $4.57 per DT higher than the
three months ended March 31, 2000.
To meet the requirements of its high priority natural gas customers
during periods of maximum demand, PSNC supplements its supplies of natural gas
with underground natural gas storage services and LNG peaking services.
Underground natural gas storage service agreements with Dominion Gas
Transmission, Columbia Gas Transmission and Transco provide for storage capacity
of approximately 8,657 MMCF. In addition, PSNC's own LNG facility is capable of
storing the liquefied equivalent of 1,000 MMCF of natural gas with daily
regasification capability of 106 MMCF. Approximately 911 MMCF were in storage at
December 31, 2001. LNG storage service agreements with Transco, Cove Point LNG
and Pine Needle LNG provide for approximately 1,266 MMCF of storage space, all
of which was filled at December 31, 2001.
The Company believes that supplies under long-term contract and
supplies available for spot market purchase are adequate to meet existing
customer demands and to accommodate growth.
Gas Marketing - Nonregulated
Energy Marketing's activities are primarily focused in the Southeast,
where it markets natural gas and provides energy-related risk management
services to producers and consumers. Energy Marketing is also a power marketer,
which allows it to buy and sell large blocks of electric capacity in wholesale
markets. In addition, SCANA Energy, a division of Energy Marketing, markets
natural gas to approximately 385,000 customers (as of December 31, 2001) in
Georgia's deregulated natural gas market.
The Company's Board of Directors has established a Risk Management
Committee which is responsible for developing corporate policies and overseeing
the management of risk within tolerance parameters approved by the Board.
REGULATION
General
SCANA became a registered public utility holding company under PUHCA on
February 10, 2000. SCANA and its subsidiaries are subject to the jurisdiction of
the SEC as to financings, acquisitions and diversifications, affiliate
transactions and other matters.
SCE&G is subject to the jurisdiction of the SCPSC as to retail
electric, gas and transit rates, service, accounting, issuance of securities
(other than short-term promissory notes) and other matters.
PSNC is subject to the jurisdiction of the 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.
SCPC is subject to the jurisdiction of the SCPSC as to gas rates,
service, accounting and other matters.
Federal Energy Regulatory Commission
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 and the issuance of short-term promissory notes.
(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.)
SCE&G holds licenses under the Federal Water Power Act or the Federal
Power Act with respect to all of its hydroelectric projects. The expiration
dates of the licenses covering the projects are as follows:
License License
Project Expiration Project Expiration
Columbia 2000 Parr Shoals 2020
Saluda 2007 Stevens Creek 2025
Fairfield Pumped Storage 2020 Neal Shoals 2036
SCE&G filed an application for a new license for Columbia on June 30,
1998. The application was officially accepted for filing by FERC notice dated
December 23, 1999, and is currently in environmental review. The current license
for Columbia expired on June 30, 2000; subsequent to that date, FERC issued a
temporary operating license to allow SCE&G to continue to operate the project
until a new license is issued. SCE&G expects to transfer the Columbia Project to
the City of Columbia in 2002 in connection with SCE&G's proposed transfer of its
transit system to an unaffiliated regional transit authority. See ITEM 2,
PROPERTIES.
At the termination of a license under the Federal Power Act, the United
States government may take over the project covered thereby, or FERC may extend
the license or issue a license to another applicant. If the Federal government
takes over a project or FERC issues a license to another applicant, the original
licensee is entitled to be paid its net investment in the project, not to exceed
fair value, plus severance damages.
For a discussion of SCE&G's agreement with FERC related to reinforcing
the Lake Murray Dam (related to the Saluda hydroelectric project), see previous
discussion under Capital Requirements and see Liquidity and Capital Resources in
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G.
Nuclear Regulatory Commission
SCE&G is subject to regulation by the 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 is responsible for the review, in
conjunction with the NRC, of certain aspects of emergency planning relating to
the operation of nuclear plants.
FERC Orders No. 636, 888 and 2000
The Company's regulated business operations were impacted by FERC
Orders No. 636, 888 and 2000. Order No. 636 was intended to deregulate the
markets for interstate sales of natural gas by requiring that pipelines provide
transportation services that are equal in quality for all gas suppliers whether
the customer purchases gas from the pipeline or another supplier. Orders No. 888
and 2000 require utilities under FERC jurisdiction that own, control or operate
transmission lines to file nondiscriminatory open access tariffs that offer to
others the same transmission service they provide to themselves and to submit
plans for the possible formation of an RTO. The Company believes it will
continue to be able to meet successfully the challenges of these altered
business climates and does not anticipate there will be any material adverse
impact from these Orders on the Company's results of operations, cash flows,
financial position or business prospects.
As already noted, Order No. 2000 required utilities which operate
electric transmission systems to submit plans for the possible formation of
RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other
southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth)
as an independent regional transmission company, responsible for operating and
planning the utilities' combined transmission systems. In July 2001 FERC
expressed its desire that utilities throughout the United States combine their
transmission systems to create four large independent regional operators, one
each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered
mediation talks to take place between the utilities forming GridSouth and
certain groups that had proposed other RTOs. These talks were mediated by an
administrative law judge, who issued her nonbinding mediation report to FERC in
September 2001. The report made recommendations related to the formation of a
Southeast regional RTO. While FERC has not acted on the mediation report, and
the timing or impact of future FERC orders related to RTOs cannot be predicted,
SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in
connection with RTO formation.
RATE MATTERS
For a discussion of the impact of various rate matters, see Regulatory
Matters in the Liquidity and Capital Resources section of Management's
Discussion and Analysis of Financial Condition and Results of Operations for
SCANA and SCE&G, and the Notes to Consolidated Financial Statements appearing in
Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 4), SCE&G
(Note 3) and PSNC (Note 5).
General
SCE&G and PSNC's gas rate schedules for their residential and small
commercial customers include a WNA. SCE&G's and PSNC'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;
however, it does reduce fluctuations caused by abnormal weather.
Fuel Cost Recovery Procedures
The SCPSC has established a fuel cost recovery procedure which
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 has
the right to request a formal proceeding at any time should circumstances
dictate such a review. In the April 2001 annual review of the fuel cost
component of electric rates, the SCPSC increased the fuel cost component of the
electric rate to 15.79 mills per KWH.
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 a fixed cost of gas, based on projections,
as established by the SCPSC in annual gas cost and gas purchase practice
hearings. Any differences between actual and projected gas costs are deferred
and included when projecting gas costs during the next annual gas cost recovery
hearing.
PSNC operates under two rate provisions in addition to WNA that serve
to reduce fluctuations in PSNC's earnings. First, its Rider D rate mechanism
allows PSNC to recover, in any manner authorized by the NCUC, margin losses on
negotiated gas sales. The Rider D rate mechanism also allows PSNC to recover
from customers all prudently incurred gas costs, including changes in natural
gas prices. Second, PSNC operates with full margin transportation rates. These
rates allow PSNC to earn the same margin on gas delivered to customers
regardless of whether the gas is sold or only transported by PSNC to the
customer.
PSNC'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 and changes in the rates charged by PSNC's pipeline
transporters. PSNC may file revised tariffs with the NCUC coincident with these
changes or it may track the changes in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC's gas purchasing practices annually.
SCPC's cost of gas is calculated and recovered each month based on
actual costs incurred using a method approved by the SCPSC. A review of costs
and calculations is performed by the SCPSC in its annual review of the purchased
gas adjustments and gas purchasing policies.
ENVIRONMENTAL MATTERS
General
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 forecast. For a more complete discussion of how these
regulations and standards impact the Company, SCE&G and PSNC, see the
Environmental Matters section of Management's Discussion and Analysis of
Financial Condition and Results of Operations for SCANA and SCE&G.
Capital Expenditures
In the years 1999 through 2001, the Company's capital expenditures for
environmental control totaled approximately $79.7 million (including
approximately $74.8 million for SCE&G). This was in addition to expenditures
included in "Other operation and maintenance" expenses, which were approximately
$23.0 million, $19.6 million, and $18.2 million during 2001, 2000 and 1999,
respectively (including approximately $17.0 million, $16.6 million and $15.0
million for SCE&G during 2001, 2000 and 1999, respectively). It is not possible
to estimate all future costs for environmental purposes, but forecasts for
capitalized environmental expenditures for the Company are $78.7 million for
2002 and $177.8 million for the four-year period 2003 through 2006 (including
$69.5 million for 2002 and $92.3 million for the four-year period 2003 through
2006 for SCE&G). These expenditures are included in the Company's and SCE&G's
construction program.
In October 1998 the EPA issued a final rule requiring 22 states,
including South Carolina, to modify their state implementation plans to address
the issue of NOx pollution. While not final, South Carolina has proposed NOx
reductions that would require the Company to install pollution control equipment
to reduce its NOx emission. Capital expenditures required to comply with the NOx
reductions are included in the cost figures above.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 required that the United States
government make available by 1998 a permanent repository for high-level
radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mil per KWH of
net nuclear generation after April 7, 1983. Payments, which began in 1983, are
subject to change and will extend through the operating life of SCE&G's Summer
Station. SCE&G entered into a contract with the DOE in 1983 providing for
permanent disposal of its spent nuclear fuel by the DOE. The DOE presently
estimates that the permanent storage facility will not be available until 2010.
SCE&G has on-site spent nuclear fuel storage capability until at least 2006 and
expects to be able to expand its storage capacity to accommodate the spent
nuclear fuel output for the life of the plant through spent fuel pool reracking,
dry cask storage or other technology as it becomes available. The Act also
imposes on utilities the primary responsibility for storage of their spent
nuclear fuel until the repository is available.
OTHER MATTERS
With regard to SCE&G's insurance coverage for Summer Station, reference
is made to the Notes to Consolidated Financial Statements (Note 13B for the
Company and Note 12B for SCE&G), which are incorporated herein by reference.
For a description of the Company's investments in various
telecommunications companies, see Other Matters in the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial Condition
and Results of Operations for the Company.
ITEM 2. PROPERTIES
SCANA owns no significant property other than the capital stock of each
of its subsidiaries and certain investments in ITC^DeltaCom preferred stock. It
holds, directly or indirectly, all of the capital stock of each of its
subsidiaries except for the preferred stock of SCE&G, the preferred securities
of SCE&G Trust I and 30 percent of an indirect subsidiary, in liquidation. It
also has investments in two LLCs: one operates a cogeneration facility in
Charleston, South Carolina and the other operates a lime production facility in
Charleston, South Carolina. Effective February 28, 2002 SCANA sold its interest
in the lime production facility.
SCE&G's bond indentures, securing the First and Refunding Mortgage
Bonds and First Mortgage Bonds issued thereunder, constitute direct mortgage
liens on substantially all of its property. GENCO's Williams Station is subject
to a first mortgage lien.
For a brief description of the properties of the Company'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.
ELECTRIC PROPERTIES
Information on electric generating facilities, all of which are owned by
SCE&G except as noted, is as follows:
Net Generating
Present Year Capacity
Facility Fuel Capability Location In-Service (Summer Rating) (KW)
-------- --------- -------- ---------- --------------------
Steam
-----
Urquhart (1) Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 420,000
Wateree Coal Eastover, SC 1970 700,000
Williams (2) Coal Goose Creek, SC 1973 615,000
Summer (3) Nuclear Parr, SC 1984 635,000
D-Area (4) Coal DOE Savannah River Site, SC 1995 38,000
Cope Coal Cope, SC 1996 417,000
Cogen South* Charleston, SC 1999 65,000
Gas Turbines
------------
Burton Gas/Oil Burton, SC 1961 28,500
Faber Place Gas Charleston, SC 1961 9,500
Hardeeville Oil Hardeeville, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr Gas/Oil Parr, SC 1970 60,000
Williams Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
Urquhart #4 Gas/Oil Beech Island, SC 1999 48,000
Hydro
-----
Neal Shoals Carlisle, SC 1905 5,000
Parr Shoals Parr, SC 1914 14,000
Stevens Creek Martinez, GA 1914 9,000
Columbia (5) Columbia, SC 1927 10,000
Saluda Irmo, SC 1930 206,000
Pumped Storage
--------------
Fairfield Parr, SC 1978 536,000
----------
4,544,000
(1) On September 21, 1999 SCE&G announced a $256 million gas turbine
generator project in Aiken County, South Carolina. Two combined-cycle
turbines will burn natural gas to produce 300 megawatts of new electric
generation and use exhaust heat to replace coal-fired steam that powers
two existing 75 megawatt turbines at the Urquhart Generating Station.
The turbine project is scheduled to be completed by June 2002.
(2) The steam unit at Williams Station is owned by GENCO.
(3) Represents SCE&G's two-thirds portion of the Summer Station (one-third
owned by Santee Cooper).
(4) This plant is leased from the DOE and is dedicated to DOE's Savannah
River Site steam needs. "Net Generating Capability" for this plant is
expected average hourly output. The lease expires on October 1, 2005.
(5) In connection with the proposed transfer of the transit system to an
unaffiliated regional transit authority as discussed below, this
facility is expected to be transferred to the City of Columbia in 2002.
* SCE&G receives shaft horse power from Cogen South, LLC to operate
SCE&G's generator. Cogen South, LLC is owned 50 percent by SCANA and 50
percent by Westvaco.
SCE&G owns 451 substations having an aggregate transformer capacity of
22,673,584 KVA. The transmission system consists of 3,170 miles of lines and the
distribution system consists of 16,965 pole miles of overhead lines and 4,099
trench miles of underground lines.
NATURAL GAS PROPERTIES
SCE&G's natural gas system consists of approximately 12,793 miles of
distribution mains and related service facilities. SCE&G also has propane air
peak shaving facilities which can supplement the supply of natural gas by
gasifying propane to yield the equivalent of 73 MMCF per day. These facilities
can store the equivalent of 325 MMCF of natural gas.
SCPC's natural gas system consists of approximately 1,945 miles of
transmission pipeline of up to 24 inches in diameter which connect its resale
customers' distribution systems with transmission systems of Southern Natural
and Transco. SCPC owns two LNG plants, 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. On peak days, the Charleston
facility can regasify up to 60 MMCF per day and the Salley facility can regasify
up to 90 MMCF.
PSNC's natural gas system consists of approximately 810 miles of
transmission pipeline of up to 24 inches in diameter that connect its
distribution systems with Transco. PSNC's distribution system consists of
approximately 7,425 miles of distribution mains and related service facilities.
PSNC owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to
liquefy approximately 100 MMCF per day. PSNC also owns, through a wholly owned
subsidiary, 33.21 percent of Cardinal Pipeline Company, LLC, which owns a
105-mile transmission pipeline. In addition, PSNC owns, through a wholly owned
subsidiary, 17 percent of Pine Needle LNG Company, LLC. Pine Needle owns and
operates a liquefaction, storage and regasification facility.
TRANSIT PROPERTIES
SCE&G owns 40 motor coaches used in the operation of the Columbia
transit system. The Columbia system is comprised of 17 routes covering 177
miles. SCE&G intends to dispose of its investment in the Columbia transit system
as soon as practicable, and in November 2001, signed a letter of intent to
negotiate transferring the transit system to an unaffiliated regional transit
authority. As part of the negotiations, SCE&G expects to transfer a small hydro
plant to the City of Columbia in 2002. Management is uncertain as to what the
costs associated with the disposition of the transit system will be or when the
disposition will be finalized.
ITEM 3. LEGAL PROCEEDINGS
The Company is subject to claims and assertions in the normal conduct
of its operations. For information regarding legal proceedings, see Item 1,
BUSINESS - RATE MATTERS (the Company, SCE&G and PSNC), Environmental Matters in
the Liquidity and Capital Resources section of Item 7, MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (the Company and
SCE&G), and Notes to Consolidated Financial Statements appearing in Item 8,
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Note 13C and 13E for the Company,
Note 12C and 12E for SCE&G and Note 11 for PSNC).
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
COMMON STOCK INFORMATION - SCANA Corporation
------------------ ------------------------------------------------- ------------------------------------------------
2001 2000
------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------
Price Range: (a)
High 27.99 28.49 29.03 30.00 31.13 30.94 26.88 29.00
Low 25.00 24.25 26.61 24.92 25.75 24.38 22.81 22.00
------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ -----------
(a) As reported on the New York Stock Exchange Composite Listing.
------------------------------ ------------------ ------------------ ----------- ------------------ -----------------
DIVIDENDS PER SHARE 2001 2000
------------------------------ ------------------ ------------------ ------------------ -----------------
-----------
Amount Date Declared Date Paid Amount Date Declared Date Paid
------ ------------- --------- ------ ------------- ---------
First Quarter .30 February 22, 2001 April 1, 2001 .2875 February 22, 2000 April 1, 2000
Second Quarter .30 May 3, 2001 July 1, 2001 .2875 April 27, 2000 July 1, 2000
Third Quarter .30 August 2, 2001 October 1, 2001 .2875 August 16, 2000 October 1, 2000
Fourth Quarter .30 November 1, 2001 January 1, 2002 .2875 October 17, 2000 January 1, 2001
----------------- ------------ ------------------ ------------------ ----------- ------------------ -----------------
The principal market for SCANA common stock is the New York Stock Exchange.
The ticker symbol used is SCG. The corporate name SCANA is used in newspaper
stock listings. The total number of shares of SCANA common stock outstanding
at February 28, 2002 was 104,728,268. The number of common shareholders of
record at February 28, 2002 was 41,677.
All of SCE&G and PSNC's common stock is owned by SCANA and has no market.
During 2001 and 2000 SCE&G paid $157.3 million and $130.8 million,
respectively, in cash dividends to SCANA. During 2001 and 2000 PSNC paid
$18.3 million and $19.0 million, respectively, in cash dividends to SCANA.
SECURITIES RATINGS (As of February 28, 2002)
SCANA SCE&G PSNC
---------------------------- ------------------- ---------------------------------------------- -- -----------------
First and
Medium- First Refunding Trust
Rating Term Mortgage Mortgage Preferred Preferred Commercial Senior Commercial
Agency Notes Bonds Bonds Stock Securities Paper Unsecured Paper
------ ----- ----- ----- ----- ---------- ----- --------- -----
Moody's A3 A1 A1 a2 a2 P-1 A2 P-1
Standard & A- A A BBB+ BBB+ A-1 A A-1
Poors
Fitch Ratings A- A+ A+ A A F-1 n/a n/a
---------------- ----------- ----------- ----------- ---------- ----------- ------------ ------------- -------------
Further reference regarding these debt and equity securities is made to the
Notes to Consolidated Financial Statements appearing in Item 8, FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Notes 6, 8 and 10), SCE&G (Notes
5, 7 and 9) and PSNC (Notes 7 and 8).
The Restated Articles of Incorporation of SCE&G and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that,
under certain circumstances, could limit the payment of cash dividends on
common stock. In addition, with respect to hydroelectric projects, the
Federal Power Act requires the appropriation of a portion of certain earnings
therefrom. At December 31, 2001 approximately $36.8 million of retained
earnings were restricted by this requirement as to payment of cash dividends
on common stock of SCE&G.
Item 6. Selected Financial Data
SCANA
- ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------
As of and for the Year Ended December 31, 2001 2000(1) 1999 1998 1997
- ------------------------------------------------------ ---------- ----------- ------------ ---------- ----------
(Millions of Dollars, Except Statistics and Per Share
Statement of Income Data------------------------------------------
Operating Revenues $3,451 $3,433 $2,078 $2,106 $1,725
Operating Income 528 554 353 470 425
Other Income 550 44 90 19 41
Income Before Cumulative Effect of Accounting 539 221 179 223 221
Change--------------
Net Income 539 250 179 223 221
- -------
Balance Sheet Data-------
Utility Plant, Net $5,263 $4,949 $3,851 $3,787 $3,648
Total Assets 7,822 7,427 6,011 5,281 4,932
Capitalization:
Common Equity 2,194 2,032 2,099 1,746 1,788
Preferred Stock (Not Subject to Purchase or 106 106 106 106 106
Sinking Funds)
Preferred Stock, Net (Subject to Purchase or 10 10 11 11 12
Sinking Funds)
Sce&G - Obligated Mandatorily Redeemable
Preferred
Securities of Sce&G's Subsidiary Trust,
Sce&G Trust I,
Holding Solely $50 Million Principal Amount
Of the 7.55%
Junior Subordinated Debentures of Sce&G, due 50 50 50 50 50
2027
Long-term Debt, Net 2,646 2,850 1,563 1,623 1,566
- --------------------------------------------------- ---------- ----------- ------------ ---------- ----------
- --------------------------------------------------- ---------- ----------- ------------ ----------
Total Capitalization $5,006 $5,048 $3,829 $3,536 $3,522
=================================================== ========== =========== ============ ========== ==========
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions) 104.7 104.5 103.6 105.3 107.1
Basic and Diluted Earnings Per Share $5.15 $2.40 $1.73 $2.12 $2.06
Dividends Declared Per Share of Common Stock $1.20 $1.15 $1.32 $1.54 $1.51
Other Statistics (2)
Electric:
Customers (Year-end) 547,388 537,253 523,552 517,447 503,905
Total Sales (Million Kwh) 22,928 23,352 21,744 21,203 18,852
Residential:
Average Annual Use Per Customer (Kwh) 14,196 14,596 14,011 14,481 13,214
Average Annual Rate Per Kwh $.0805 $.0787 $.0787 $.0801 $.0799
Generating Capability - Net Mw (Year-end) 4,520 4,544 4,483 4,387 4,350
Territorial Peak Demand - Net Mw 4,196 4,211 4,158 3,935 3,734
Regulated Gas:
Customers (Year-end) 646,230 637,018 260,456 257,051 252,797
Sales, Excluding Transportation (Thousand 1,183,463 1,389,975 1,013,083 1,002,952 945,289
Therms)
Residential:
Average Annual Use Per Customer (Therms) 616 644 507 521 531
Average Annual Rate Per Therm $1.17 $1.08 $.86 $.86 $.86
Nonregulated Gas:
Retail Customers (Year-end) 385,581 431,814 430,950 78,091 N/a
Firm Customer Deliveries (Thousand Therms) 359,602 431,115 229,660 4,692 N/a
Interruptible Customer Deliveries (Thousand 407,188 306,099 188,828 2,167,931 782,248
Therms)(3)
- --------------------------------------------------- ---------- ----------- ------------ ---------- ----------
SCE&G
- --- --- ---------- ---------- ---------- ---------- --------
2001 2000 1999 1998 1997
- --- --- ---------- ---------- ---------- ---------- --------
Amounts)------------------------------------------
$1,715 $1,669 $1,465 $1,450 $1,337-----
428 457 393 448 387-----
30 16 12 9 5----
222 231 189 227 195---
222 253 189 227 195--
$3,891 $3,615 $3,501 $3,432 $3,310-
4,962 4,671 4,404 4,246 4,054
1,750 1,657 1,558 1,499 1,447
106 106 106 106 106
10 10 11 11 12
50 50 50 50 50
1,412 1,267 1,121 1,206 1,262
--------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
$3,328 $3,090 $2,846 $2,872 $2,877
========== ========== ========== ========== ==========
N/a N/a N/a N/a N/a
N/a N/a N/a N/a N/a
N/a N/a N/a N/a N/a
547,411 537,286 523,581 517,472 503,930
22,928 23,353 21,746 21,204 18,853
14,196 14,596 14,011 14,481 13,214
$.0805 $.0787 $.0787 $.0801 $.0799
3,905 3,929 3,883 3,807 3,790
4,196 4,211 4,158 3,935 3,734
267,206 266,451 260,348 256,843 252,589
368,632 444,521 414, 800 405,249 381,726
509 507 521 531
563
$1.21 $.95 $.86 $.86 $.86
N/a N/a N/a N/a N/a
N/a N/a N/a N/a N/a
N/a N/a N/a N/a N/a
---------- ---------- ---------- ---------- ----------
(1) Reflects acquisition of PSNC effective January 1, 2000.
(2) Other Statistics for 2000 exclude the effect of the change in accounting for
unbilled revenues, where applicable. (3) Interruptible customer deliveries for
1998 and 1997 include volumes from the Houston office of Energy Marketing, which
was closed in 1999.
SCANA CORPORATION
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................ 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 43
Item 8. Financial Statements and Supplementary Data.................. 46
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in
this annual report) which are not statements of historical fact are intended to
be, and are hereby identified as, "forward-looking statements" for purposes of
the safe harbor provided by Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
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) that the
information is of a preliminary nature and may be subject to further and/or
continuing review and adjustment, (2) changes in the utility and nonutility
regulatory environment, (3) changes in the economy, especially in areas served
by the Company's subsidiaries, (4) the impact of competition from other energy
suppliers, (5) growth opportunities for the Company's regulated and diversified
subsidiaries, (6) the results of financing efforts, (7) changes in the Company's
accounting policies, (8) weather conditions, especially in areas served by the
Company's subsidiaries, (9) performance of and marketability of the Company's
investments in telecommunications companies, (10) inflation, (11) changes in
environmental regulations, (12) volatility in commodity natural gas markets and
(13) the other risks and uncertainties described from time to time in the
Company's periodic reports filed with the SEC. The Company disclaims any
obligation to update any forward-looking statements.
COMPETITION
Electric Operations
After the energy supply and pricing problems experienced in California
in 2000 and 2001, the efforts to restructure electric markets at the state level
have slowed considerably. Many states that had considered legislation to
restructure the electric industry have stopped such efforts or are proceeding
more slowly.
In South Carolina electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2002.
Further, while several companies have announced their intent to site merchant
generating plants in the Company's service territory, economic events,
environmental concerns and other factors have slowed those efforts. Legislation
or regulatory action at the Federal level, particularly as part of a larger
energy policy initiative, may be considered in 2002. The Company is not able to
predict whether any restructuring legislation or regulatory action will be
enacted and, if it is, the conditions it will impose on utilities.
SCANA's electric and gas utility, SCE&G, has undertaken a variety of
initiatives aimed at preparing for a restructured electric market. These
initiatives include obtaining accelerated recovery of electric regulatory
assets, establishing open access transmission tariffs and selling bulk power to
wholesale customers at market-based rates. Marketing of services to commercial
and industrial customers has increased significantly, and SCE&G has executed
long-term power supply contracts with a significant portion of its industrial
customers. The Company believes that these actions, as well as numerous others
that have been and will be taken, demonstrate its ability and commitment to
succeed in the evolving operating environment.
Gas Distribution
Effective January 1, 2000 SCANA completed its acquisition of PSNC. The
acquisition has been accounted for as a purchase. PSNC is operated as a wholly
owned subsidiary of SCANA. As a result of the transaction, SCANA became a
registered public utility holding company under PUHCA.
Gas Transmission
SCG, when operational, will provide interstate transportation services
for natural gas to markets in southeastern Georgia and South Carolina. SCG will
transport natural gas from interconnections with Southern Natural at Port
Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba
Island, near Savannah, Georgia. The endpoint of SCG's line will be at the site
of SCE&G's proposed natural gas-fired generating station in Jasper County, South
Carolina. In December 2001 SCG filed an application with FERC for a Certificate
of Public Convenience and Necessity to acquire and build a pipeline from Elba
Island, Georgia to Jasper County, South Carolina. The project has an anticipated
in-service date of November 2003.
SCPC's plan to convert from a closed system to an open-access
transportation-only system has been postponed indefinitely due to a number of
factors, including the impact of the current economic downturn and the lack of
consistent customer support for the proposed plan of system conversion.
Retail Gas Marketing
SCANA Energy, the Company's nonregulated retail gas division in Georgia,
has maintained its position as the second largest marketer in Georgia, with an
approximate 27 percent market share. Due to record high natural gas prices and
cold winter temperatures, the Georgia Public Service Commission (GPSC) adopted
emergency rules which prohibited gas marketers from disconnecting service to
residential customers for non-payment from mid-January through March 2001.
Customers were also permitted to switch marketers without first paying
outstanding balances owed to their previous provider. As a result of this
action, SCANA Energy increased its allowance for uncollectible accounts in the
first quarter of 2001 and, to the extent permitted by other GPSC rules, has
implemented more stringent credit policies.
Since that time, the GPSC has remained extremely active in its review
and oversight of the natural gas marketplace. In the summer of 2001 the GPSC
placed restrictions on the length of time that customer deposits may be held by
marketers and also called for other changes in the ways that marketers interact
with their customers. Further, in September, Georgia's Governor called for the
formation of a task force to study the impact of natural gas deregulation. In
January 2002 that task force reported its recommendations regarding further
restructuring. The Georgia legislature is currently considering bills which, if
enacted, would allow electric membership cooperatives to seek certification to
market natural gas and provide for the establishment of a regulated alternative
supplier of gas services. These actions raise concern as to the level of
additional restrictions which may be placed on marketers, including SCANA
Energy, and heighten the risks of SCANA Energy's business efforts in that
market.
SCANA Energy and SCANA's other natural gas distribution, transmission
and marketing segments maintain gas inventory and also utilize forward contracts
and financial instruments, including futures contracts, to manage their exposure
to fluctuating commodity natural gas prices. (See Note 12 of Notes to
Consolidated Financial Statements.) As a part of this risk management process, a
portion of SCANA's projected natural gas needs has been purchased or otherwise
placed under contract. This factor and others (e.g., the level of bad debts
experienced) are, in the aggregate, used to establish retail pricing levels at
SCANA Energy. As a result of the potential regulatory actions discussed above
and other downward pricing pressures inherent in the competitive market, SCANA
Energy may be unable to sustain its current levels of customers and/or pricing,
thereby reducing expected margins and profitability.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash requirements arise primarily from the operational
needs of SCANA subsidiaries, the Company's construction program, the activities
or investments of SCANA's subsidiaries and payment of dividends. The ability of
SCANA's regulated subsidiaries to replace existing plant investment, as well as
to expand to meet future demand for electricity and gas, will depend upon their
ability to attract the necessary financial capital on reasonable terms. SCANA's
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 the regulated
subsidiaries continue their ongoing construction programs, the Company expects
to seek increases in rates. The Company's future financial position and results
of operations will be affected by the regulated subsidiaries' ability to obtain
adequate and timely rate and other regulatory relief, if requested.
The estimated primary cash requirements for 2002 and the actual
primary cash requirements for 2001, excluding requirements for non-nuclear fuel
purchases, short-term borrowings and dividends, are as follows:
Millions of Dollars 2002 2001
- ---------------------------------------------------------------------- ---------
Property additions and construction expenditures,
net of AFC $677 $544
Nuclear fuel expenditures 6 4
Investments 18 46
Maturing obligations, redemptions and sinking
and purchase fund requirements 714 317
- --------------------------------------------------------------------------- ----
Total $1,415 $911
=========================================================================== ====
Approximately 41 percent of total cash requirements was provided from
internal sources in 2001 as compared to 39 percent in 2000.
For the years 2003-2006 the Company has an aggregate of $1,034.3 million
of long-term debt and preferred stock maturing, which includes an aggregate of
$576.3 million for SCE&G, $2.2 million of purchase or sinking fund requirements
for SCE&G's preferred stock and $21.4 million for PSNC. SCE&G's long-term debt
maturities for the years 2003-2006 include approximately $93.8 million for
sinking fund requirements all of which may be satisfied by deposit and
cancellation of bonds issued upon the basis of property additions or bond
retirement credits. These obligations and other commitments are tabulated below.
Contractual Cash Obligations
Less than After
December 31, 2001 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of Dollars)
Long-term and short-term debt
(including interest) $5,364 $1,071 $1,217 $399 $2,677
Preferred stock sinking funds 11 1 2 1 7
Capital leases 3 1 2 - -
Operating leases 90 17 37 19 17
Other commercial commitments 1,025 509 305 30 181
Included in other commercial commitments are estimated obligations under
forward contracts for natural gas purchases. Certain of these contracts relate
to regulated gas businesses; therefore, the effects of such contracts on gas
costs are reflected in gas rates. The 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 to these commercial commitments, the Company is party to
certain New York Mercantile Exchange (NYMEX) futures contracts for which any
unfavorable market movements have already been funded in cash. These derivatives
are accounted for as cash flow hedges under Statement of Financial Accounting
Standards (SFAS) No. 133 and their effects are reflected within other
comprehensive income until such time as underlying transactions occur.
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. Sales of additional equity securities may
also occur. The Company expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the foreseeable future.
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 state and
Federal regulatory bodies including state public service commissions, the SEC
and FERC. The following paragraphs describe the financing programs currently
utilized by the Company.
SCANA Corporation
SCANA has in effect a medium-term note program for the issuance from
time to time of unsecured medium-term debt securities. While issuance of these
securities requires customary approvals discussed above, the Indenture under
which they are issued contains no specific limit on the amount which may be
issued.
At December 31, 2001 SCANA had $163 million of unused authorized lines
of credit, of which $50 million was committed and the remainder was uncommitted.
Amounts outstanding under SCANA's lines of credit totaled $0 and $85 million at
December 31, 2001 and 2000, respectively.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail
electric, gas and transit rates, service, accounting, issuance of securities
(other than short-term promissory notes) and other matters.
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945
(Old Mortgage), contains provisions prohibiting the issuance of additional bonds
thereunder (Class A Bonds) unless net earnings (as therein defined) for 12
consecutive months out of the 18 months prior to the month of issuance are at
least twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 2001 the Bond Ratio
was 5.77. The Old Mortgage allows the issuance of Class A Bonds up to an
additional principal amount equal to (i) 70 percent of unfunded net property
additions (which unfunded net property additions totaled approximately $1,759
million at December 31, 2001), (ii) retirements of Class A Bonds (which
retirement credits totaled $44.9 million at December 31, 2001), and (iii) cash
on deposit with the Trustee.
SCE&G is also subject to a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties under which its
future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued
under the New Mortgage on the basis of a like principal amount of Class A Bonds
issued under the Old Mortgage which have been deposited with the Trustee of the
New Mortgage. New Bonds will be issuable under the New 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 (including Class A Bonds) and New
Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 2001
the New Bond Ratio was 5.71.
SCE&G's Restated Articles of Incorporation prohibit issuance of
additional shares of preferred stock without the consent of the preferred
shareholders unless net earnings (as defined therein) 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, 2001,
the Preferred Stock Ratio was 1.83.
Without the consent of at least a majority of the total voting power of
SCE&G's preferred stock, SCE&G may not 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;
however, 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, 2001 SCE&G had $250 million of unused authorized lines of
credit under a credit agreement supporting the issuance of commercial paper.
SCE&G's commercial paper outstanding at December 31, 2001 and 2000 was $114.7
million and $117.5 million, respectively. In addition, Fuel Company has a credit
agreement for a maximum of $125 million with the full amount available at
December 31, 2001. The credit agreement supports the issuance of short-term
commercial paper for the financing of nuclear and fossil fuels and sulfur
dioxide emission allowances. Fuel Company commercial paper outstanding at
December 31, 2001 and 2000 was $50.1 million and $70.2 million, respectively.
This commercial paper and amounts outstanding under the revolving credit
agreement, if any, are guaranteed by SCE&G.
Public Service Company of North Carolina, Incorporated
PSNC has in effect a medium-term note program for the issuance from time
to time of unsecured medium-term debt securities.
At December 31, 2001 PSNC had $125 million unused authorized lines of
credit under a credit agreement supporting the issuance of commercial paper.
PSNC had no commercial paper outstanding on December 31, 2001. PSNC's commercial
paper outstanding at December 31, 2000 was $125 million.
Financing Transactions and Other Information
The following financing transactions have occurred since January 1, 2001:
o On January 24, 2001 SCANA issued $202 million of two-year floating rate
notes maturing on January 24, 2003. The interest rate is reset quarterly
based on three-month LIBOR plus 110 basis points. Proceeds from the debt
were used to reduce short-term debt and for general corporate purposes.
o On January 24, 2001 SCE&G issued $150 million of first mortgage bonds
having an annual interest rate of 6.70 percent and maturing on February 1,
2011. The proceeds from the sale of these bonds were used to reduce
short-term debt and for general corporate purposes.
o On February 16, 2001 PSNC issued $150 million of medium-term notes having
an annual interest rate of 6.625 percent and maturing on February 15, 2011.
The proceeds were used to reduce short-term debt and for general corporate
purposes.
o On May 9, 2001 SCANA issued $300 million of medium-term notes maturing May
15, 2011 and bearing a fixed interest rate of 6.875 percent. SCANA also
entered into an interest rate swap agreement, designated as a fair value
hedge, to pay variable rate and receive fixed rate interest payments. The
proceeds from the issuance of the medium-term notes were used to refinance
$300 million of bank notes originally issued to finance SCANA's acquisition
of PSNC. The swap agreement was terminated and replaced with another swap
agreement to pay variable rate and receive fixed rate interest payments,
also designated as a fair value hedge, in August 2001. Approximately $6.5
million received upon the original swap's termination is being amortized
over the term of the associated debt.
o On December 19, 2001 PSNC entered into two interest rate swap agreements to
pay variable rate and receive fixed rate interest payments on a combined
notional amount of $44.9 million. These swaps were designated as fair value
hedges of PSNC's $12.9 million, 10 percent senior debentures due 2004 and
$32.0 million, 8.75 percent senior debentures due 2012.
o On January 31, 2002 SCANA issued $250 million of medium-term notes maturing
February 1, 2012 and bearing a fixed interest rate of 6.25 percent. Also on
January 31, 2002 SCANA issued $150 million of two-year floating rate notes
maturing on February 1, 2004. The interest rate on the floating rate notes
is reset quarterly based on three-month LIBOR plus 62.5 basis points.
Proceeds from these issuances were used to refinance $400 million of
two-year floating rate notes that matured on February 8, 2002, which had
been issued to finance SCANA's acquisition of PSNC.
o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1,
2032. The proceeds from the sale of these bonds were used to reduce
short-term debt primarily incurred as a result of SCE&G's construction
program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent
Series due August 15, 2021.
The Company's electric and natural gas businesses are seasonal in nature,
with the primary demand for electricity being experienced during summer and
winter and the primary demand for natural gas being experienced during winter.
As a result of the significant increase during the latter half of 2000 in the
cost to the Company of natural gas and the colder than normal weather
experienced in December, the Company experienced significant increases in its
working capital requirements, contributing to the need for the financings by
SCANA and PSNC in early 2001 described above. The more recent borrowings were
necessitated by the cash requirements of the construction program, including the
projects described below.
SCE&G is constructing a $256 million gas turbine generator project in
Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas
to produce 300 megawatts of new electric generation and use exhaust heat to
replace coal-fired steam that powers two existing 75 megawatt turbines at the
Urquhart Generating Station. The turbine project is scheduled to be completed by
June 2002.
In October 1999 FERC notified SCE&G of its agreement with SCE&G's plan
to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001, is expected to cost $250 million and be completed in
2005. Any costs incurred by SCE&G are expected to be recoverable through
electric rates.
In October 2001 SCE&G filed with the SCPSC its siting plans to construct
an 875 megawatt generation facility in Jasper County, South Carolina, to supply
electricity to its South Carolina customers. The facility will include three
natural gas combustion-turbine generators and one steam-turbine generator.
Construction of the $450 million facility is expected to begin in April 2002,
with commercial operation in the summer of 2004. In connection with the
facility, SCE&G has signed a 250 megawatt electric supply contract with North
Carolina Electric Membership Corporation for a term of at least nine years
beginning January 1, 2004.
ENVIRONMENTAL MATTERS
Electric Operations
The Clean Air Act Amendments of 1990 (CAA) required electric utilities
to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by
the year 2000. The Company's compliance with these reductions has been
accomplished. The EPA has indicated that it will propose regulations by December
2003 for stricter limits on mercury and other toxic pollutants generated by
coal-fired plants.
SCE&G and GENCO currently estimate that air emissions control equipment
will require capital expenditures of $165 million over the 2002-2006 period to
retrofit existing facilities, with increased operation and maintenance costs of
approximately $1.8 million per year. To meet compliance requirements for the
years 2007 through 2011, the Company anticipates additional capital expenditures
of approximately $82 million.
In October 1998 the EPA issued a final rule requiring 22 states,
including South Carolina, to modify their state implementation plans to address
the issue of NOx pollution. While not final, South Carolina has proposed NOx
reductions that would require the Company to install pollution control equipment
to reduce its NOx emissions. Capital expenditures will be required to comply
with the NOx reductions and they are included in the cost figures above.
The EPA has undertaken an aggressive enforcement initiative against the
industry and the Department of Justice has brought suit against a number of
utilities in Federal court alleging violations of the CAA. 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 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).
The Company and SCE&G 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. 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. The regulations also provide an
exemption for an increase in emissions resulting from increased hours of
operation or production rate and from demand growth. It is possible that the EPA
will commence enforcement actions against SCE&G, 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 assertions relative to the Company's and SCE&G's
compliance with the CAA would be without merit. However, if successful, such
assertions could have a material adverse effect on the Company's financial
position, cash flows and results of operations.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require treatment for wastewater discharges. Under
this 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 in
monitoring and controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company has been developing compliance
plans for these initiatives. Amendments to the Clean Water Act proposed in
Congress include several provisions which, if passed, could prove costly to
SCE&G and GENCO. These include, but are not limited to, limitations to mixing
zones and the implementation of technology-based standards.
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 could differ significantly from the
original estimates. Amounts estimated and accrued to date for site assessments
and cleanup relate to regulated operations and are deferred and amortized with
recovery provided through rates. Deferred amounts for SCE&G, net of amounts
previously recovered through rates and insurance settlements, totaled $24.4
million and $20.2 million at December 31, 2001 and 2000, respectively. The
deferral includes the estimated costs associated with the following matters.
o In September 1992 the EPA notified SCE&G, among others, of its potential
liability for the investigation and cleanup of the Calhoun Park area site
in Charleston, South Carolina. This site encompasses approximately 30 acres
and includes properties which were locations for various industrial
operations, including one of SCE&G's decommissioned MGPs. Field work at the
site began in November 1993 and has required the submission of several
investigative reports and the implementation of several work plans. In
September 2000 SCE&G was notified by the South Carolina Department of
Health and Environmental Control (DHEC) that benzene contamination was
detected in the intermediate aquifer on surrounding properties of the
Calhoun Park area site. The EPA required that SCE&G conduct a focused
Remedial Investigation/Feasibility Study on the intermediate aquifer, which
was completed in June 2001. The EPA expects to issue a Record of Decision
dealing with the intermediate aquifer and sediments in June 2002. SCE&G
anticipates that major remediation activities will be completed in 2003,
with certain monitoring activities continuing until 2007. As of December
31, 2001, SCE&G has spent approximately $15.8 million to remediate the
Calhoun Park area site. Total remediation costs are estimated to be $21.9
million.
o SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently
being remediated under work plans approved by DHEC. SCE&G is continuing to
investigate the remaining site and is monitoring the nature and extent of
residual contamination. SCE&G anticipates that major remediation activities
for these three sites will be completed between 2003-2005. SCE&G has spent
approximately $2.0 million related to these sites, and expects to incur an
additional $6.0 million.
In addition, PSNC owns, or has owned, all or portions of seven sites in
North Carolina on which MGPs were formerly operated. Intrusive investigation
(including drilling, sampling and analysis) has begun at two sites and the
remaining sites have been evaluated using historical records and observations of
current site conditions. These evaluations have revealed that MGP residuals are
present or suspected at several of the sites. PSNC estimates that the cost to
remediate the sites would range between $11.3 million and $21.9 million. The
estimated cost range has not been discounted to present value. PSNC's associated
actual costs for these sites will depend on a number of factors, such as actual
site conditions, third-party claims and recoveries from other PRPs. At December
31, 2001 PSNC has recorded a liability and associated regulatory asset of $9.1
million, which reflects the minimum amount of the range, net of shared cost
recovery expected from other PRPs and expenditures for work completed. Amounts
incurred to date are approximately $1.1 million. Management believes that all
MGP cleanup costs incurred will be recoverable through gas rates.
REGULATORY MATTERS - STATE
Regulated public utilities are allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory environment occur, the Company may no longer be eligible to apply
this accounting treatment and may be required to eliminate such regulatory
assets from its balance sheet. Although the potential effects of deregulation
cannot be determined at present, discontinuation of the accounting treatment
could have a material adverse effect on the Company's results of operations in
the period the write-off would be recorded. It is expected that cash flows and
the financial position of the Company would not be materially affected by the
discontinuation of the accounting treatment. The Company reported approximately
$244 million and $100 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $142 million and $76 million, respectively, on its
balance sheet at December 31, 2001.
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 these
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, 2001 the Company's net investment in fossil/hydro and nuclear
generation assets was $1,559.7 million and $572.9 million, respectively.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail
electric, gas and transit rates, service, accounting, issuance of securities
(other than short-term promissory notes) and other matters.
Electric
On April 24, 2001 the SCPSC approved SCE&G's request to increase the
fuel component of rates charged to electric customers from 1.330 cents per
kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2001 through April 2002. The increase
also provides recovery over a two-year period of under-collected actual fuel
costs through April 2001, including short-term purchased power costs
necessitated by outages at two of SCE&G's base load generating plants in winter
2000-2001. The new rates were effective as of the first billing cycle in May
2001.
On September 14, 1999 the SCPSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan was implemented beginning
January 1, 2000 for a three-year period. The SCPSC approved an accelerated
capital recovery methodology wherein SCE&G may increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year. As of December 31, 2001,
no accelerated depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
On January 9, 1996 the SCPSC authorized a return on common equity of
12.0 percent. The SCPSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a ten-year
period. Additionally, the SCPSC approved accelerated amortization of a
significant portion of SCE&G's electric regulatory assets (excluding deferred
income tax assets) and the remaining transition obligation for postretirement
benefits other than pensions, which enabled SCE&G to recover the balances as of
the end of the year 2000.
Gas
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 component in effect during the years ended December
31, 2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.993 January-February 2001 $.543 January-July 2000
$.793 March-October 2001 $.688 August-October 2000
$.596 November-December 2001 $.782 November-December 2000
On July 5, 2000 the SCPSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million. The retroactive effect was
recorded in the second quarter of 2000.
In 1994 the SCPSC issued an order approving SCE&G's request to recover
through a billing surcharge to its gas customers the costs of environmental
cleanup at the sites of former MGPs. The billing surcharge is subject to annual
review and provides for the recovery of substantially all actual and projected
site assessment and cleanup costs and environmental claims settlements for
SCE&G's gas operations that had previously been deferred. In October 2001, as a
result of the annual review, the SCPSC approved SCE&G's request to increase the
billing surcharge from 1.1 cents per therm to 3.0 cents per therm, which is
intended to provide for the recovery, prior to the end of the year 2005, of the
balance remaining at December 31, 2001 of $24.4 million.
Transit
In September 1992 the SCPSC issued an order granting SCE&G's request for
a $.25 increase in transit fares from $.50 to $.75 in Columbia, South Carolina;
however, the SCPSC also required $.40 fares for low income customers and denied
SCE&G's request for certain bus route and schedule changes. The new rates were
placed into effect in October 1992. After several appeals and petitions for
reconsideration to the Circuit Court and the Supreme Court by the various
parties, on September 27, 2000 the SCPSC issued an order granting certain relief
requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion
with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC accepted
the Consumer Advocate's motion and issued a stay of its order. The Consumer
Advocate and other intervenors have petitioned the Circuit Court for judicial
review of the SCPSC's order granting relief. The Circuit Court has held in
abeyance any appellate review pending the outcome of current negotiations on the
transfer of the transit system from SCE&G to an unaffiliated regional transit
authority.
Public Service Company of North Carolina, Incorporated
PSNC 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.
PSNC'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 and changes in the rates charged by PSNC's pipeline
transporters. PSNC may file revised tariffs with the NCUC coincident with these
changes or it may track the changes in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the years ended December
2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2000
$.750 February-March 2001 $.265 February-May 2000
$.650 April-August 2001 $.350 June 2000
$.500 September-October 2001 $.450 July-September 2000
$.350 November-December 2001 $.490 October-December 2000
On April 6, 2000 the NCUC issued an order permanently approving PSNC's
request to establish its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas. This
mechanism allows PSNC to collect from its customers amounts approximating the
amounts paid for natural gas.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. On June 29, 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million. The Madison County portion of the project was completed at a cost
of approximately $5.8 million, and customers began receiving service in July
2001.
On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by
approximately $1 million in each of August 2000 and August 2001, and agreed to a
moratorium on general rate cases until August 2005. General rate relief can be
obtained during this period to recover costs associated with materially adverse
governmental actions and force majeure events.
On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County and
authorized disbursements from the fund of approximately $4.3 million. Most of
Alexander County lies within PSNC's certificated service territory and did not
previously have natural gas service. The project was completed at a cost of
approximately $4.8 million, and customers began receiving natural gas service in
March 2000.
SCANA Energy - Georgia
See discussion at COMPETITION regarding the regulatory framework of the
Company's business in the Georgia retail natural gas market.
REGULATORY MATTERS - FEDERAL
Effective with its acquisition of PSNC, SCANA became a registered
public utility holding company under PUHCA. SCANA and its subsidiaries are
subject to the jurisdiction of the SEC as to financings, acquisitions and
diversifications, affiliate transactions and other matters.
The Company's regulated business operations were impacted by FERC Orders
No. 636, 888 and 2000. Order No. 636 was intended to deregulate the markets for
interstate sales of natural gas by requiring that pipelines provide
transportation services that are equal in quality for all gas suppliers whether
the customer purchases gas from the pipeline or another supplier. Orders No. 888
and 2000 require utilities under FERC jurisdiction that own, control or operate
transmission lines to file nondiscriminatory open access tariffs that offer to
others the same transmission service they provide to themselves and to submit
plans for the possible formation of an RTO. In the opinion of the Company, it
continues to be able to meet successfully the challenges of these altered
business climates and does not anticipate any material adverse impact on the
results of operations, cash flows, financial position or business prospects.
As already noted, Order No. 2000 required utilities which operate
electric transmission systems to submit plans for the possible formation of
RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other
southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth)
as an independent regional transmission company, responsible for operating and
planning the utilities' combined transmission systems. In July 2001 FERC
expressed its desire that utilities throughout the United States combine their
transmission systems to create four large independent regional operators, one
each in the Northeast, Southeast, Midwest and West. Accordingly FERC ordered
mediation talks to take place between the utilities forming GridSouth and
certain groups that had proposed other RTOs. These talks were mediated by an
administrative law judge, who issued her nonbinding mediation report to FERC in
September 2001. The report made recommendations related to the formation of a
Southeast regional RTO. While FERC has not acted on the mediation report, and
the timing or impact of future FERC orders related to RTOs cannot be predicted,
SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in
connection with RTO formation.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of the Company's accounting policies which
are new or most critical in terms of reporting results of operations.
SFAS 71 - SCANA's regulated utilities are subject to the provisions of
SFAS 71, 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. Aside from other impacts which might be experienced as a result
of deregulation or other significant changes in the regulatory environments of
the utilities, SFAS 71 could cease to be applicable and the Company could be
required to write off such regulatory assets and liabilities (see also
COMPETITION).
Provisions for bad debts / Allowances for doubtful accounts - As of each
balance sheet date, SCANA and its subsidiaries evaluate the collectibility of
accounts receivable and record allowances for doubtful accounts based on
estimates of the level of actual write-offs which might be experienced. These
estimates are based on, among other things, comparisons of the relative age of
accounts and consideration of actual write-off history.
Investments in debt and equity securities - SCANA and certain of its
subsidiaries hold investments in marketable securities, some of which are
subject to SFAS 115 mark-to-market accounting and some of which are considered
cost basis investments for which determination of fair value historically has
been considered impracticable. Equity holdings subject to SFAS 115 are
categorized as "available for sale" and are carried at quoted market, with any
unrealized gains and losses credited or charged to other comprehensive income
within common equity on the Company's balance sheet. Debt securities are
categorized as "held to maturity" and are carried at amortized cost. When
indicated, and in accordance with its stated accounting policy, SCANA performs
periodic assessments of whether any decline in the value of these securities to
amounts below SCANA'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.
During 2001, as a result of a determination that an other than temporary
decline in value (an impairment) had occurred, SCANA wrote down its investments
in ITC^DeltaCom in the amount of approximately $35 million (net of tax).
Similarly, on March 1, 2002 the Company determined that the decline in
value of its investment in DTAG to below its cost basis of $20.30 per share was
other than temporary, and recorded an impairment loss of approximately $160
million (after tax). (See Note 16 to Notes to Consolidated Financial
Statements.)
SCANA also from time to time holds investments in joint ventures,
partnerships or other equity method investees for which evaluation of the
existence and quantification of "other than temporary" declines in value may be
required. Whenever indicated these write-downs are also recorded through
earnings. During 2001 SCANA wrote down two such investments in the aggregate
amount of $9 million (net of tax).
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, and it does not engage in off-balance sheet financing or
similar transactions other than incidental operating leases in the normal course
of business, generally for office space, furniture and equipment.
Goodwill amortization and impairment analysis - SFAS 141, "Business
Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued
during 2001. SFAS 141 will require all future acquisitions to be accounted for
utilizing the purchase method. SCANA considers the amounts categorized by FERC
as "acquisition adjustments" to be goodwill as defined in SFAS 142 and has
ceased amortization of such amounts upon the adoption of SFAS 142 effective
January 1, 2002. In 2001 the amount of such amortization expense recorded was
$14 million. This amortization related to acquisition adjustments of
approximately $466 million carried on the books of PSNC and approximately $40
million carried on the books of SCPC.
As required by the provisions of SFAS 142, the Company is performing
initial valuation analyses to determine whether these carrying amounts are
impaired, and if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement the Company will have completed the initial stage of those analyses by
June 30, 2002. If any write-downs are indicated by those analyses, they will be
quantified and recorded by the end of 2002. Because the Company is in the early
stages of these analyses the effect, if any, of the adoption of the impairment
provisions of the Statement is not known; however, if write-downs are considered
necessary, they could be material to the Company's results of operations for
2002.
Pension accounting - SCANA follows SFAS 87 in accounting for its defined
benefit pension plan. SCANA's plan is fully funded and as such, significant 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 returns on
assets. Net pension income of $43.3 million recorded in 2001 reflects the use of
an 8 percent discount rate and an assumed 9.5 percent long-term return on plan
assets. SCANA believes that these assumptions are, and that the resulting
pension income amount is, reasonable. Were SCANA to have alternatively selected
a discount rate of 7.5 percent and a rate of return on assets of 9 percent, the
net pension income recorded in 2001 would have been reduced by approximately
$6.2 million.
Accounting for postretirement benefits other than pensions - Similar to
its pension accounting, SCANA follows SFAS 106 in accounting for its
postretirement medical and life insurance benefits. This plan is unfunded, so no
return on assets impacts 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 8 percent and recorded a net SFAS 106
cost of $17.5 million for 2001. Were the selected discount rate to have been 7.5
percent, the expense would have been approximately $0.5 million higher.
Derivatives - Effective January 1, 2001 SCANA follows the provisions of
SFAS 133 in accounting for its derivatives and hedging activities. Substantially
all of SCANA's use of derivatives occurs in the normal course of its risk
management processes and is generally confined to contracts which qualify for
hedge accounting treatment under the provisions of SFAS 133. The Company is
party to interest rate swaps and to NYMEX traded natural gas contracts. The
Company values its NYMEX gas derivatives at fair value based on quoted market
prices, and values an insignificant number (and value) of non-exchange traded
gas-related derivatives using information provided by counterparties to those
transactions or by reference to quoted market prices of listed contracts. The
estimated fair value of interest rate swaps is similarly based on settlement
amounts obtained from the counterparties.
As a result of adopting SFAS 133 the Company recorded a credit of
approximately $23.0 million, net of tax, as the effect of a change in accounting
principle (transition adjustment) to other comprehensive income on January 1,
2001. This amount represents the reclassification of unrealized gains that were
deferred and reported as liabilities at December 31, 2000. In the future all
gains and losses related to qualifying cash flow hedges deferred in other
comprehensive income will be reclassified to earnings at the time the hedged
transactions affect earnings.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," are effective January 1, 2002. This Statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
AFFILIATE TRANSACTIONS
SCANA and its consolidated affiliates engage in certain intercompany
transactions, subject to the restrictions imposed by PUHCA. Among these
transactions are the sale of gas to SCE&G by SCPC and the provision of
administrative services to all members of the consolidated group by SCANA
Services.
In addition to these transactions and investment transactions discussed
at "Other Matters," the Company has engaged in the following transactions with
other entities considered to be affiliates.
SCE&G has two equity-method investments in partnerships involved in
converting coal to alternate fuel, the use of which fuel qualifies for favorable
Federal income tax treatment (tax credits). The aggregate investment in these
partnerships as of December 31, 2001 is approximately $3 million, and through
December 31, 2001, they had generated and passed through to SCE&G approximately
$28 million in such tax credits. Under a plan approved by the SCPSC, any tax
credits generated and ultimately passed through to SCE&G have been and will be
deferred and used to offset defined capital expenditures such as those related
to reduction of environmental emissions.
OTHER MATTERS
Radio Service Network
SCI owns an 800 Mhz radio service network within South Carolina, and in
June 2001, agreed to subcontract the operation and maintenance of its network to
Motorola, Inc. (Motorola) for the period July 1, 2001 through March 31, 2002.
SCI intends to sell the network to Motorola at a purchase price in excess of its
carrying value.
Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of the propane gas
assets of SCANA filed suit against SCANA in Circuit Court seeking unspecified
damages. The suit alleges the existence of a contract for the sale of assets to
the plaintiff and various causes of action associated with that contract. The
Company is confident in its position and intends to vigorously defend the
lawsuit. The Company does not believe that the resolution of this issue will
have a material impact on its results of operations, cash flows or financial
position.
SCANA and Westvaco each own a 50 percent interest in Cogen South LLC
(Cogen). Cogen built and operates a cogeneration facility in North Charleston,
South Carolina. On September 10, 1998 the contractor in charge of construction
filed suit in Circuit Court alleging that it incurred construction cost overruns
relating to the facility and that the construction contract provides for
recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were
named as defendants in the suit. Cogen filed a separate suit against the
contractor for delay and performance issues. The suits were combined and the
contractor brought the manufacturer of the generator into the performance suit.
In November 2001 a settlement was reached between all parties. Terms of the
settlement are confidential, but the settlement's impact on SCANA and SCE&G's
results of operations, cash flow and financial position is not material.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
Telecommunications Investments
At December 31, 2001 SCANA and SCH, a wholly owned, indirect subsidiary
of SCANA, held investments in the marketable equity and debt securities of the
following companies in the amounts noted in the table below.
Unrealized
Investee Held By Securities (a) Basis Market (b) Gain/(Loss)
(c)
- ------------------------------ ------------------------------------------------------- ----------------- ----------- ---------------
(Millions of dollars)
DTAG SCH 39.3 million ordinary shares $798.0 $664.3 ($133.7)
ITC SCH 3.1 million common stock 5.8 n/a
(d)
SCH 645,153 series A convertible preferred stock 7.2 n/a
(d)
SCH 133,664 series B convertible preferred stock 4.0 n/a
(d)
ITC^DeltaCom SCH 5.1 million common stock 4.4 -
4.4 (e)
SCH 1.5 million series A convertible preferred stock,
convertible
March 2002 2.6 -
2.6 (e)
SCANA 5,113 series B-1 preferred stock convertible into
877,193
shares of common stock 0.8 -
0.8 (e)
SCANA 6,667 series B-2 preferred stock convertible into
2,604,297
shares of common stock 2.3 -
2.3 (e)
SCANA Warrants to purchase approximately 1.0 million shares
of
common stock 0.8 -
0.8 (e)
Knology SCH 7.2 million series A preferred stock, convertible 5.0 (d) n/a
upon an initial public offering and warrants to
purchase
159,000 shares of series A preferred stock,
convertible upon an initial public offering
SCH 8.3 million series C preferred stock, convertible 25.0 (d) n/a
upon an initial public offering
Knology
Broadband SCH $71,050,000 face amount, 11.875% Senior Discount
Notes due 2007 64.9 (d) n/a
(a) Convertible preferred stock is convertible into common stock at any time
unless otherwise indicated.
(b) As converted, based on market value of underlying common stock, where
applicable.
(c) Amounts are included in accumulated other comprehensive income (loss),
net of taxes.
(d) Market value not readily determinable.
(e) Reflects write-down for "other than temporary" impairment as discussed
below.
DTAG is an international telecommunications carrier. The Company's
investment in DTAG was received in exchange for approximately 14.9 million
shares of Powertel, Inc. (Powertel) which SCH owned prior to DTAG's acquisition
of Powertel in May 2001. SCH recorded a non-cash, after-tax gain of $354.4
million as a result of the exchange.
On March 1, 2002 the Company determined that the decline in value of its
investment in DTAG to below its cost basis of $20.30 per share was other than
temporary, and recorded an impairment loss of approximately $160 million (after
tax). (See Note 16 of Notes to Consolidated Financial Statements.) On March 21,
2002 the Company announced that SCH had sold 21 million ordinary shares of DTAG
at a weighted average price of $14.82 per share through a series of market
transactions between March 4, 2002 and March 21, 2002. The sales resulted in net
after tax proceeds of approximately $250 million.
ITC Holding Company (ITC) holds ownership interests in several Southeastern
communications companies. ITC^DeltaCom is a fiber optic telecommunications
provider and an affiliate of ITC. Knology, Inc. (Knology) is a broadband service
provider of cable television, telephone and internet services. Knology is an
affiliate of ITC. Knology Broadband, Inc. (Knology Broadband) is a wholly-owned
subsidiary of Knology and an affiliate of ITC.
In the fourth quarter of 2001 the Company determined that the decline in
value of its investment in ITC^DeltaCom (to below cost) was other than
temporary. Accordingly the Company recorded an impairment charge of
approximately $35.0 million (after-tax).
RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share of common stock and cash dividends declared for
2001, 2000 and 1999 were as follows:
2001 2000 1999
------------------------------------------------------------------------------
------------------------------------------------------------------------------
Earnings derived from:
Continuing operations $2.15 $2.12 $1.39
Non-recurring gains 3.42 - .34
Investment impairment (.42) - -
Cumulative effect of accounting change,
net of taxes - .28 -
------------------------------------------------------------------------------
Earnings per weighted average share $5.15 $2.40 $1.73
==============================================================================
Cash dividends declared (per share) $1.20 $1.15 $1.32
============================================================== =========== ===
o 2001 vs 2000 Earnings derived from continuing operations increased $.03,
primarily as a result of improved results from retail gas marketing ($.03),
improved results from energy marketing ($.09), completion of repairs at
Summer Station in 2000 ($.04), a decrease in imputed interest expense
related to the PSNC acquisition in 2000 ($.05) and other ($.02). These
improvements were partially offset by a decrease in electric margin ($.11)
and a decrease in regulated gas margin ($.09).
o 2000 vs 1999 Earnings derived from continuing operations increased $0.73,
primarily as a result of improved results from retail gas marketing ($.04
net earnings for 2000 compared to $.45 loss in 1999) and the acquisition of
PSNC ($.20). In addition electric margin improved $.36 (see discussion at
Electric Operations), regulated gas margin (excluding PSNC) improved $.07
and pension income increased $.05. These improvements were partially offset
by increased interest expense of $.36, a charge for repairs at Summer
Station ($.04) and other increases in operation and maintenance ($.04).
Pension income recorded by the Company reduced operations expense by
$22.6 million, $22.6 million and $17.3 million for the years ended December 31,
2001, 2000 and 1999, respectively. In addition pension income increased other
income by $12.7 million, $12.8 million and $10.5 million for the years ended
December 31, 2001, 2000 and 1999, respectively. Effective July 1, 2000 the
Company's pension plan was amended to provide a cash balance formula. The effect
of this plan amendment was to reduce net periodic benefit income for the year
ended December 31, 2000 by approximately $3.7 million.
In 2001 the Company recognized a non-recurring gain of $3.38 per share
in connection with the sale of its investment in Powertel, which was acquired by
DTAG in May 2001. The Company also recognized a gain of $.04 per share in
connection with the sale of the assets of SCANA Security in March 2001. In 2001
the Company also recorded impairment charges related to investments in
ITC^DeltaCom ($.34), a developer of micro-turbine technology ($.04) and a lime
production plant ($.04). In 2000 the cumulative effect of an accounting change
resulted from the recording of unbilled revenues by SCANA's retail utility
subsidiaries (see Note 2 of Notes To Consolidated Financial Statements).
Non-recurring gains resulted from the sale of retail propane assets ($.29) and
telecommunications towers ($.05) in 1999.
The Company's financial statements include the recording of an 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. An equity portion of AFC
is included in nonoperating income and a debt portion of AFC is included in
interest charges (credits) as noncash items, both of which have the effect of
increasing reported net income. AFC represented approximately 3.0 percent of
income before income taxes in 2001, 2.3 percent in 2000 and 2.4 percent in 1999.
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G,
GENCO and Fuel Company. Electric operations sales margins (including
transactions with affiliates) for 2001, 2000 and 1999, excluding the cumulative
effect of accounting change in 2000, were as follows:
Millions of dollars 2001 2000 1999
- --------------------------------------------- --------------- ----------------
Operating revenues $1,368.7 $1,343.8 $1,226.0
Less: Fuel used in generation (283.3) (294.9) (284.6)
Purchased power (138.1) (82.5) (35.9)
- --------------------------------------------- ------------- -- ----------------
Margin $947.3 $966.4 $905.5
============================================= =============== ================
o 2001 vs 2000 Sales margin decreased primarily due to milder weather and the
impact of the slowing economy, which was partially offset by customer
growth and lower fuel costs.
o 2000 vs 1999 Sales margin increased primarily due to more favorable weather
and customer growth.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes, excluding volumes attributable to the cumulative effect of
accounting change in 2000, were as follows:
Classification 2001 % Change 2000 % Change
- ------------------------------------------------- ------------------ ------------- ------------
Residential (170,509) (2.5%) 6.3%
396,179
Commercial (16,830) - 6.0%
354,350
Industrial (317,659) (4.8%) 8.5%
524,969
Sales for resale
(excluding interchange) (108,236) (8.8%) 2.8%
33,505
Other (18,927) (3.4%) 6.7%
34,676
- ------------------------------------------------- -------------
Total territorial (632,161) (3.0%) 1,343,679 6.7%
Negotiated Market Sales Tariff 207,984 10.0% 15.7%
264,257
- ------------------------------------------------- -------------
Total (424,177) (2.0%) 1,607,936 7.4%
================================================= ================== ============= ============
o 2001 vs 2000 Sales volume decreased primarily due to milder weather and the
impact of the slowing economy.
o 2000 vs 1999 Sales volume increased primarily due to more favorable weather
and customer growth.
In March 2001 Summer Station returned to service after having been taken
out of service on October 7, 2000 for a planned maintenance and refueling
outage. During initial inspection activities, plant personnel discovered a small
leak in a weld in a primary coolant system pipe. Repairs were completed and the
integrity of the new welds was verified through extensive testing. The NRC was
closely involved throughout this process and approved SCE&G's actions, as well
as the restart schedule.
Also in April 2001 SCE&G's 385 megawatt coal-fired Cope Generating
Station returned to service after having been taken out of service in January
2001 due to an electrical ground in the generator. The SCPSC has approved
recovery of the cost of replacement power related to both of these outages
through SCE&G's fuel adjustment clause.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC. Gas distribution sales margins (including transactions with
affiliates) for 2001, 2000 and 1999, excluding the cumulative effect of
accounting change in 2000, were as follows:
Millions of dollars 2001 2000 1999
- ---------------------------------------- ------------- -------------
Operating revenues 793.6 $745.9 $239.0
Less: Gas purchased for resale 537.8) (486.3) (152.6)
- ---------------------------------------- ------------- -------------
Margin 255.8 $259.6 $86.4
======================================== ============= =============
SCANA acquired PSNC effective January 1, 2000. Therefore the Company's sales for
1999 do not include PSNC.
o 2001 vs 2000 Sales margin decreased primarily as a result of the
slowing economy and increased competition with alternate fuels.
o 2000 vs 1999 Sales margin increased primarily due to the acquisition
of PSNC, which contributed $161.5 million, and improved margin at
SCE&G due primarily to more favorable weather.
Increases (decreases) from the prior year in dekatherm (DT) sales volume
by classes, including transportation gas and excluding volumes attributable to
the cumulative effect of accounting change in 2000, were as follows:
Classification 2001 % Change 2000 % Change
- ------------------------------- -------------
Residential (7,068,050) (18.1%) 27,211,306 230.2%
Commercial (2,613,154) (10.0%) 14,493,448 123.9%
Industrial (2,859,885) (12.7%) 4,484,199 25.0%
Transportation gas (3,318,646) (10.5%) 29,523,281 *
Sales for resale * *
882 407
- ----------------------------------- -------------
Total (15,858,853) (13.3%) 75,712,641 174.2%
=================================== =============== ============= =============
*Not meaningful
o 2001 vs 2000 Sales volume decreased due to the slowing economy and use
of alternate fuels by industrial customers.
o 2000 vs 1999 Sales volume increased primarily as a result of the
acquisition of PSNC, which accounted for 72.6 million DTs. SCE&G's
sales volume increased approximately 2.0 million DTs due to colder
weather and customer growth, which were partially offset by
curtailments and use of alternate fuels by industrial customers.
Gas Transmission
Gas Transmission is comprised of SCPC. Gas transmission sales margins
(including transactions with affiliates) for 2001, 2000 and 1999 were as
follows:
Millions of dollars 2001 2000 1999
- ------------------------------------------ ------------- -------------
Operating revenues $478.0 $489.0 $342.4
Less: Gas purchased for resale (434.1) (434.7) (295.1)
- ------------------------------------------ ------------- -------------
Margin $43.9 $54.3 $47.3
========================================== ============= =============
o 2001 vs 2000 Sales margin decreased primarily as a result of decreased
volume of sales to industrial customers due to competitive pricing of
alternate fuels and a slowing economy, decreased volume of sales to
electric generation due to milder weather and reduced margins in sales
for resale as a result of milder weather.
o 2000 vs 1999 Sales margin increased primarily as a result of increased
contract and sales volumes from sales for resale and margin earned
from industrial customers.
Increases (decreases) from the prior year in DT sales volume by classes
including transportation were as follows:
Classification 2001 % Change 2000 % Change
---------------------------------- ----------------------------------------
Commercial (422,070) (37.2%) 22,132 24.2%
Industrial (101,275,260) (25.8%) (5,212,904) (11.7%)
Transportation 7,250,560 32.1% 10,296 0.5%
Sales for resale (95,295,980) (15.3%) 3,542,185 6.0%
---------------------------------- ---------------
Total (189,742,750) (18.3%) (1,638,291) (1.6%)
================================== ========================================
o 2001 vs 2000 Commercial and industrial volumes decreased due to
increased gas to gas competition and the slowing economy.
Transportation volumes increased due to increased gas to gas
competition. Sales for resale volumes decreased due to milder weather.
o 2000 vs 1999 Sales for resale volumes increased as a result of colder
temperatures. The sales volume for industrial customers decreased due
to decreased sales to electric generation facilities and decreased
sales to other customers with alternate fuel sources.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's deregulated natural gas
market. Retail gas marketing revenues and net income (loss) for 2001, 2000 and
1999 were as follows:
Millions of dollars 2001 2000 1999
----------------------------------- --------------- ----------------
Operating revenues $628.1 $547.3 $206.6
Net income (loss) 7.6 4.4 (44.8)
----------------------------------- --------------- ----------------
o 2001 vs 2000 Operating revenues increased due to cold weather and
record high gas costs early in the year. Net income increased
primarily as a result of increases in gross margins on gas sales.
o 2000 vs 1999 Operating revenues increased as a result of customer
growth, favorable weather and a successful gas supply and pricing
strategy. Net income increased as a result of the increase in revenue
and significant reductions in customer acquisition and advertising
expenditures.
Delivered volumes for 2001, 2000 and 1999 totaled approximately 76.7
million, 73.8 million and 40.9 million DT, respectively, which include
interruptible volumes of approximately 40.7 million, 30.6 million and 18.9
million DT for the same periods, respectively.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Energy marketing operating revenues and net
income(loss) for 2001, 2000 and 1999 were as follows:
Millions of dollars 2001 2000 1999
--------------------------------- --------------- ----------------
Operating revenues $438.9 $543.8 $223.3
Net income (loss) 2.6 (4.2) (3.9)
--------------------------------- --------------- ----------------
o 2001 vs 2000 Operating revenues decreased primarily due to lower
prices for natural gas in the latter part of the year and the closing
of the Midwest and California offices. Net income increased primarily
due to improved margins.
o 2000 vs 1999 Operating revenues increased primarily due to increased
prices for natural gas. Net loss increased primarily due to increased
bad debts.
Delivered volumes for 2001, 2000 and 1999 totaled approximately 75.3
million, 83.9 million and 103.7 million DT, respectively. The decrease in
volumes for 2001 resulted from the closing of the Midwest and California offices
and the decrease in volumes for 2000 resulted from the closing of the Houston
office.
Other Operating Expenses
Increases in other operating expenses were as follows:
Millions of dollars 2001 % Change 2000 % Change
- ------------------------------------------- ------------------------------------
Other operation and maintenance $3.5 0.7% $66.1 16.1%
Depreciation and amortization 7.2 3.3% 47.4 28.1%
Other taxes 1.5 21.3% 10.6 10.3%
- ------------------------------------------- -----------
Total $12.2 1.5% $124.1 18.2%
=========================================== ====================================
o 2001 vs 2000 Other operation and maintenance expenses increased
primarily as a result of increases in employee benefit costs.
Depreciation and amortization increased primarily as a result of
normal increases in utility plant. Other taxes increased primarily due
to increased property taxes.
o 2000 vs 1999 Other operating expenses increased primarily as a result
of the acquisition of PSNC. This acquisition accounted for the
following increases: other operation and maintenance ($67.5 million),
depreciation and amortization ($41.9 million, of which $13.4 million
is attributable to the amortization of the acquisition adjustment),
and other taxes ($6.4 million).
Apart from the PSNC acquisition, other operation and
maintenance expense decreased $1.4 million due to pension
income (see Earnings and Dividends), which was partially
offset by increased maintenance costs for electric
generating and distribution facilities. Depreciation and
amortization increased $5.5 million primarily due to
normal increases in utility plant. Other taxes increased
$4.2 million primarily due to increased property taxes.
Other Income
Increases (decreases) in other income, excluding the equity component of
AFC, were as follows:
Millions of dollars 2001 % Change 2000 % Change
- --------------------------------------- ------------ ------------ ------------
Gain on sale of investments $545.3 * - -
Gain on sale of assets 10.1 * $(64.8) (95.3%)
Impairment of investments (61.9) * - -
Other income 0.8 2.1% 18.6 96.4%
- --------------------------------------- ------------
Total $494.3 * $(46.2) (52.9%)
======================================= ============ ============ ============
*Not meaningful
o 2001 vs 2000 Other income increased primarily as a result of
the non-recurring gain recognized in May 2001 in connection
with the exchange of the Company's investment in Powertel for
shares of DTAG, and the March 2001 gain on the sale of the
assets of SCANA Security. These gains were partially offset by
the impairments recorded related to investments in
ITC^DeltaCom, a developer of micro-turbine technology and a
lime production plant.
o 2000 vs 1999 Other income decreased primarily as a result of the sale
in 1999 of nonregulated propane assets and telecommunications towers.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
Millions of dollars 2001 % Change 2000 % Change
----------------------------------------------------------------------------
Interest on long-term debt, net $17.8 8.6% $73.8 55.8%
Other interest expense (14.4) (58.8%) 10.7 77.5%
--------------------------------------------- ----------
Total $3.4 1.5% $84.5 57.9%
============================================================================
o 2001 vs 2000 Interest expense increased primarily as a result of increased
borrowings which was partially offset by declining variable interest rates,
the Company's use of interest rate swap contracts to convert higher fixed
rate debt to lower variable rate debt and a decrease in the weighted
average interest rate on other long-term and short-term debt.
o 2000 vs 1999 Interest expense increased primarily as a result of financing
the acquisition of PSNC and related repurchase of SCANA shares ($46.0
million) and interest incurred on PSNC debt that was assumed as a result of
the acquisition ($19.6 million). In addition, interest expense increased as
a result of increased borrowings and increased weighted average interest
rates on long-term and short-term borrowings.
Income Taxes
Income taxes increased approximately $163.8 million for the year 2001
compared to 2000 and increased approximately $29.7 million for the year 2000
compared to 1999. Changes in 2001 income taxes are primarily due to the
recording of deferred income taxes in connection with the non-recurring gain
recorded in May 2001 arising from the exchange of the Company's investment in
Powertel for shares of DTAG. Changes in 2000 income taxes are primarily due to
changes in operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
December 31, 2001 Expected Maturity Date
Millions of dollars
Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value
---------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- --------------
Long-Term Debt:
Fixed Rate ($) 38.3 298.5 187.0 182.0 162.8 1,728.0 2,596.6 2,602.8
Average Fixed Interest Rate 7.21 6.38 7.58 7.43 8.63 7.02
6.64
Variable Rate ($) 700.0 202.0 - - - - 902.0 898.2
Average Variable Interest Rate 2.82 3.45 - - - -
2.96
Interest Rate Swaps:
Pay Variable/Receive Fixed ($) - - 12.9 - - 332.0 344.9 1.2
Average Pay Interest Rate - - 7.82 - - 2.96 3.15
Average Receive Interest Rate - 10.0 - - 6.21 6.35
-
December 31, 2000 Expected Maturity Date
Millions of dollars
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value
---------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- --------------
Long-Term Debt:
Fixed Rate ($) 40.9 337.3 297.2 186.3 182.0 1,267.4 2,311.1 2,232.2
Average Fixed Interest Rate 7.27 7.36 6.38 7.58 7.43 7.25
7.35
Variable Rate ($) 550.0 150.0 - - - 700.0 699.7
-
Average Variable Interest Rate 7.26 7.48 - - - 7.31
-
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.
In addition the Company has an investment in the 11.875 percent senior
discount notes (due 2007) of a telecommunications company, the cost basis of
which is approximately $64.9 million. As these notes are not actively traded,
determination of their fair value is not practicable.
Commodity price risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.
December 31, 2001 Expected Maturity in 2002 Expected Maturity in 2003
- ------------------ ---------------------------- --------------------------
Millions of dollars Weighted Weighted
Avg Avg
Settlement Contract Fair Settlement Contract Fair
Natural Gas Derivatives: Price Amount Value Price Amount Value
- ----------------------------- ------------- --------------- ----------- -------------- ------------ -----------
Futures Contracts:
Long ($) 2.63 119.3 76.0 3.26 3.0 2.6
Short ($) 2.64 1.6 1.1 - - -
December 31, 2000 Expected Maturity in 2001
- ------------------ -------------------------
Millions of dollars Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- ------------------------------------- ------------------- ---------------- ------------
Futures Contracts:
Long ($) 6.58 60.0 85.9
Short ($) 6.30 1.4 2.1
The Company uses derivative instruments to hedge forward purchases and
sales 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 NYMEX futures
contracts or options and over-the-counter instruments such as swaps, which are
typically offered by energy and financial institutions.
Risk limits are established to control the level of market, credit,
liquidity and operational/administrative risks assumed by the Company. The
Company's Board of Directors has delegated the authority for setting market risk
limits to the Risk Management Committee, which is comprised of members of senior
management, the Company's Controller, the Senior Vice President of SCPC and the
President of Energy Marketing. The Risk Management Committee provides assurance
to the Board of Directors with regard to compliance with risk management
policies 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 for transactions that are allowed.
The NYMEX futures information above includes those financial positions of
both Energy Marketing and SCPC. The ultimate effects of the hedging activities
of SCPC are passed through to its customers through SCPC's fuel adjustment
clauses.
Equity price risk - Investments in telecommunications companies' equity
securities are carried at their market value or, if market value is not readily
determinable, at their cost. The Company's investments in such securities
totaled $722.3 million at December 31, 2001. A temporary decline in value of ten
percent would result in a $72.2 million reduction in fair value and a
corresponding adjustment, net of tax effect, to the related equity account for
unrealized gains/losses, a component of other comprehensive income. An other
than temporary decline in value of ten percent would result in a $72.2 million
reduction in fair value and a corresponding adjustment to net income, net of tax
effect.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditors' Report............................................ 47
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2001 and 2000.......... 48
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999.................................. 50
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001,
2000 and 1999...................................................... 51
Consolidated Statements of Capitalization as of December 31, 2001 and 2000. 52
Consolidated Statements of Comprehensive Income and Changes in Common
Equity for the Years Ended December 31, 2001, 2000 and 1999..........54
Notes to Consolidated Financial Statements...............................55
INDEPENDENT AUDITORS' REPORT
SCANA Corporation:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of SCANA Corporation (Company) as of December 31, 2001 and 2000
and the related Consolidated Statements of Income, Comprehensive Income and
Changes in Common Equity and of Cash Flows for each of the three years in the
period ended December 31, 2001. Our audits also include the financial statement
schedule listed in Part IV at Item 14. 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 auditing standards generally accepted
in the United States of America. 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 the Company at December 31, 2001
and 2000 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001 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 as set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for operating
revenues associated with its regulated utility operations.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 8, 2002
(March 1, 2002 as to Note 16)
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
- -------------------------------------------------------------------------------------------- ---------------------
December 31, (Millions of dollars) 2001 2000
- -------------------------------------------------------------------------------------------- ---------------------
Assets
Utility Plant (Notes 1 & 6):
Electric $4,855 $4,747
Gas 1,536 1,435
Other 187 187
- -------------------------------------------------------------------------------------------- ---------------------
Total 6,578 6,369
Less accumulated depreciation and amortization 2,364 2,212
- -------------------------------------------------------------------------------------------- ---------------------
Total 4,214 4,157
Construction work in progress 544 261
Nuclear fuel, net of accumulated amortization 45 57
Acquisition adjustments-gas, net of accumulated amortization (Note 3) 460 474
- -------------------------------------------------------------------------------------------- ---------------------
Utility Plant, Net 5,263 4,949
- -------------------------------------------------------------------------------------------- ---------------------
Nonutility Property, net of accumulated depreciation 93 79
Investments (Note 12) 191 203
- -------------------------------------------------------------------------------------------- ---------------------
Nonutility Property and Investments, Net 284 282
- -------------------------------------------------------------------------------------------- ---------------------
Current Assets:
Cash and temporary investments (Notes 1 & 12) 212 159
Receivables (Net of allowance for uncollectible
accounts of $37 and $31) 424 694
Inventories (At average cost) (Note 7):
Fuel 164 107
Materials and supplies 59 56
Emission allowances 13 20
Prepayments and other 21 16
Investments (Note 12) 664 479
- -------------------------------------------------------------------------------------------- ---------------------
Total Current Assets 1,557 1,531
- -------------------------------------------------------------------------------------------- ---------------------
Deferred Debits:
Environmental 34 31
Nuclear plant decommissioning fund (Note 1) 79 72
Pension asset, net (Note 5) 239 196
Other regulatory assets (Note 1) 210 213
Other (Note 1) 156 153
- -------------------------------------------------------------------------------------------- ---------------------
Total Deferred Debits 718 665
- -------------------------------------------------------------------------------------------- ---------------------
Total $7,822 $7,427
============================================================================================ =====================
182
------------------------------------------------------------------------- --------------------- ---------------------
December 31, (Millions of dollars) 2001 2000
------------------------------------------------------------------------- --------------------- ---------------------
Capitalization and Liabilities
Shareholders' Investment:
Common equity (Note 9) $2,194 $2,032
Preferred stock (Not subject to purchase or sinking funds) (Note 10) 106 106
------------------------------------------------------------------------- --------------------- ---------------------
Total Shareholders' Investment 2,300 2,138
Preferred Stock, net (Subject to purchase or sinking funds) (Note 10) 10 10
SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal
amount of the 7.55% Junior Subordinated
Debentures of SCE&G, due 2027 (Note 10) 50 50
Long-Term Debt, net (Notes 6 & 12) 2,646 2,850
------------------------------------------------------------------------- --------------------- ---------------------
Total Capitalization 5,006 5,048
------------------------------------------------------------------------- --------------------- ---------------------
Current Liabilities:
Short-term borrowings (Notes 7, 8 & 12) 165 398
Current portion of long-term debt (Note 6) 739 41
Accounts payable 275 394
Customer prepayments and deposits 41 27
Taxes accrued 82 54
Interest accrued 45 42
Dividends declared 34 32
Deferred income taxes, net (Notes 1 & 11) 154 98
Other 26 30
------------------------------------------------------------------------- --------------------- ---------------------
Total Current Liabilities 1,561 1,116
------------------------------------------------------------------------- --------------------- ---------------------
Deferred Credits:
Deferred income taxes, net (Notes 1 & 11) 720 721
Deferred investment tax credits (Notes 1 & 11) 118 119
Reserve for nuclear plant decommissioning (Note 1) 79 72
Postretirement benefits (Note 5) 122 113
Other regulatory liabilities 100 70
Other 116 168
------------------------------------------------------------------------- --------------------- ---------------------
Total Deferred Credits 1,255 1,263
------------------------------------------------------------------------- --------------------- ---------------------
Commitments and Contingencies (Note 13) - -
------------------------------------------------------------------------- --------------------- ---------------------
Total $7,822 $7,427
========================================================================= ===================== =====================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME
------------------------------------------------------------------------ ---------------- --------------- -------------- --
For the Years Ended December 31, 2001 2000 1999
------------------------------------------------------------------------ ---------------- --------------- -------------- --
(Millions of Dollars, except per share amounts)
Operating Revenues (Notes 1, 2 & 4):
Electric $1,369 $1,344 $1,226
Gas - Regulated 1,015 998 422
Gas - Nonregulated 1,067 1,091 430
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Operating Revenues 3,451 3,433 2,078
------------------------------------------------------------------------ ---------------- --------------- ----------------
Operating Expenses:
Fuel used in electric generation 283 295 285
Purchased power 138 82 36
Gas purchased for resale 1,681 1,694 721
Other operation and maintenance 482 477 411
Depreciation and amortization (Note 1) 224 217 169
Other taxes 115 114 103
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Operating Expenses 2,923 2,879 1,725
------------------------------------------------------------------------ ---------------- --------------- ----------------
Operating Income 528 554 353
------------------------------------------------------------------------ ---------------- --------------- ----------------
Other Income (Expense):
Other income, including allowance for equity funds
used during construction (Note 1) 54 41 22
Gain on sale of assets 13 3 68
Gain on sale of investments (Note 12) 545 - -
Impairment of investments (Note 12) (62) - -
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Other Income 550 44 90
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Interest Charges, Income Taxes, Preferred Stock
Dividends and Cumulative Effect of Accounting Change 1,078 598 443
Interest Charges, Net of Allowance for Borrowed Funds 223 225 142
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 855 373 301
Income Taxes (Note 11) 305 141 111
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 550 232 190
Preferred Dividend Requirement of SCE&G - Obligated Mandatorily
Redeemable Preferred Securities 4 4 4
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Cash Dividends on Preferred Stock of Subsidiary
and Cumulative Effect of Accounting Change 546 228 186
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 7 7 7
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Cumulative Effect of Accounting Change 539 221 179
Cumulative Effect of Accounting Change, net of taxes (Note 2) - 29 -
------------------------------------------------------------------------ ---------------- --------------- ----------------
Net Income $539 $250 $179
======================================================================== ================ =============== ================
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $5.15 $2.12 $1.73
Cumulative Effect of Accounting Change, net of taxes (Note 2) - .28 -
------------------------------------------------------------------------ ---------------- --------------- ----------------
Basic and Diluted Earnings Per Share $5.15 $2.40 $1.73
======================================================================== ================ =============== ================
Weighted Average Shares Outstanding (millions) 104.7 104.5 103.6
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
For the Years Ended December 31, (Millions of dollars) 2001 2000 1999
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Cash Flows From Operating Activities:
Net income $539 $250 $179
Adjustments to reconcile net income to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes - (29) -
Depreciation and amortization 236 227 177
Amortization of nuclear fuel 16 16 18
Gain on sale of assets and investments (558) (3) (68)
Impairment of investments 62 - -
Hedging activities (65) - -
Allowance for funds used during construction (26) (9) (7)
Over (under) collection, fuel adjustment clauses 20 (25) (6)
Changes in certain assets and liabilities:
(Increase) decrease in receivables 262 (258) (36)
(Increase) decrease in inventories (53) 3 (14)
(Increase) decrease in pension asset (43) (43) (29)
(Increase) decrease in other regulatory assets (3) 4 19
Increase (decrease) in deferred income taxes, net 189 61 19
Increase (decrease) in other regulatory liabilities 22 6 (7)
Increase (decrease) in postretirement benefits 9 15 11
Increase (decrease) in accounts payable (119) 155 (30)
Increase (decrease) in taxes accrued 28 (55) 14
Other, net (20) 76 (15)
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Net Cash Provided From Operating Activities 496 391 225
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (523) (334) (238)
Purchase of subsidiary, net of cash acquired - (212) -
Proceeds on sale of assets 28 8 112
Increase in nonutility property (25) (27) (23)
Increase in investments (46) (20) (74)
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Net Cash Used For Investing Activities (566) (585) (223)
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Cash Flows From Financing Activities:
Proceeds from issuance of First Mortgage Bonds 149 148 99
Proceeds from issuance of notes and loans 648 998 200
Proceeds from swap settlement 6 - -
Repayment of mortgage bonds - (100) (10)
Repayment of notes and loans (317) (175) (77)
Repayment of other long-term debt - (8) (10)
Repurchase of preferred stock - (1) -
Repurchase of common stock - (488) -
Dividend payments on common stock (123) (124) (148)
Dividend payments on preferred stock of subsidiary (7) (7) (7)
Short-term borrowings, net (233) (6) 5
- ------------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided From Financing Activities 123 237 52
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Net Increase in Cash and Temporary Investments 53 43 54
Cash and Temporary Investments, January 1 159 116 62
- --------------------------------------------------------------------------------------- ---------------- -------------- ------------
Cash and Temporary Investments, December 31 $212 $159 $116
======================================================================================= ================ ============== ============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $11, $6 and $4) $219 $207 $138
- Income taxes 71 120 70
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available for sale, net of tax (226) (197) 311
In connection with the purchase of Public Service Company of North Carolina,
Incorporated in 2000, assets with a fair value of $1,177 million were acquired,
cash of $212 million was paid, SCANA stock valued at $488 million was issued,
and liabilities of $477 million were assumed.
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
December 31, (Millions of dollars) 2001 2000
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Common Equity (Note 9):
Common stock, without par value, authorized 150,000,000 shares; issued and
outstanding, 104,728,268 shares in 2001 and 2000 $1,043 $1,043
Accumulated other comprehensive income (loss) (113) 139
Retained earnings 1,264 850
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Total Common Equity 2,194 44% 2,032 40%
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds)
$100 Par Value - Authorized 1,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Redemption Price
Outstanding
Series 2001 2000
------ ---- ----
$100 Par 6.52% 1,000,000 1,000,000 100.00 100 100
$50 Par 5.00% 125,209 125,209 52.50 6 6
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Total Preferred Stock (Not subject to purchase or sinking funds) (Note 10) 106 2% 106 2%
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase and sinking funds)
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 2001
and 2000 $50 Par Value - Authorized 1,560,287 shares
Shares Outstanding Redemption Price
Series 2001 2000
------ ---- ----
4.50% 8,397 9,600 51.00 1 1
4.60% (A) 14,052 16,052 51.00 1 1
4.60% (B) 54,400 57,800 50.50 3 3
5.125% 66,000 67,000 51.00 3 3
6.00% 66,635 69,835 50.50 3 3
--------- ------------
Total 209,484 220,287
========= ============
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 2001 and 2000
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
Total Preferred Stock (Subject to purchase or sinking funds) 11
11
Less: Current portion, including sinking fund requirements (1)
(1)
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 10 & 12) 10 - % -%
10
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 10) 50 1% 1%
50
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
---------------------------------------------------------------------- -- -------------- -------- -------------- -----------
December 31, (Millions of dollars) 2001 2000
---------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Long-Term Debt (Notes 6 & 12)
SCANA Corporation:
Medium-Term Notes: Series Year of Maturity
3.08%(1) 2002 $300 $300
2.63%(2) 2002 400 400
6.51% 2003 20 20
6.05% 2003 60 60
6.25% 2003 75 75
3.45%(3) 2003 202 -
7.44% 2004 50 50
6.90% 2007 25 25
5.81% 2008 115 115
6.875% 2011 300 -
(1) Current rate, based on three-month LIBOR + 65 basis points, reset
quarterly (2) Current rate, based on three-month LIBOR + 50 basis points
reset quarterly (3) Current rate, based on three-month LIBOR + 110 basis
points, reset quarterly
Bank note, due 2002-2003, LIBOR rate, reset 1, 2, 3 or 6 months - 300
South Carolina Electric & Gas Company:
First Mortgage Bonds: Series Year of Maturity
6 1/4% 2003 100 100
7.70% 2004 100 100
7 1/2% 2005 150 150
6 1/8% 2009 100 100
6.70% 2011 150 -
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage Bonds: Series Year of Maturity
9% 2006 131 131
8 7/8% 2021 103 103
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984, due 2014 (6.50%) 57 57
Orangeburg County Series 1994, due 2024 (5.70%) 30 30
Other 16 17
Charleston Franchise Agreement, due 1997-2002 4 7
South Carolina Generating Company, Inc.:
Berkeley County Pollution Control Facilities Revenue
Bonds, Series 1984 due 2014 (6.50%) 36 36
Note, 7.78%, due 2011 41 49
Public Service Company of North Carolina, Incorporated:
Senior Debentures: Series Year of Maturity
10% 2004 13 17
8.75% 2012 32 32
6.99% 2026 50 50
7.45% 2026 50 50
Medium-Term Notes 6.625% 2011 150 -
South Carolina SCPC Notes, 6.72%, due 2013 15 16
Other 7 4
---------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Long-Term Debt 3,382 2,894
Less - Current maturities, including sinking fund requirements (739) (41)
- Unamortized premium (discount) 3 (3)
---------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Long-Term Debt, Net 2,646 53% 2,850 57%
---------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Capitalization $5,006 100% $5,048 100%
====================================================================== == ============== ======== ============== ===========
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND CHANGES IN COMMON EQUITY
- ------------------------------------------------ ------------------------- ------------------------- ---------------------------
For the years Ended December 31, 2001 2000 1999
- ------------------------------------------------ ------------------------- ------------------------- ---------------------------
(Millions of Dollars)
Common Comprehensive Common Comprehensive Common Comprehensive
Equity Income Equity Income Equity Income
Retained Earnings:
Balance at January 1 $850 $720 $678
Net Income 539 $539 250 $250 179 $179
Dividends declared on common stock (125) (120) (137)
--------- --------- -----
Balance at December 31 1,264 850 720
-- ----- ---- --- - ---
Accumulated other comprehensive income:
Balance at January 1 139 336 25
Unrealized gains (losses) on securities,
net of
taxes ($(121), $(106) and $165 in
2001, 2000,
and 1999, respectively) (226) (226) (197) (197) 311 311
Cumulative effect of change in accounting
For hedging activities, net of taxes 23 23
($12 in 2001)
Unrealized losses on hedging activities,
net of taxes ($(26) in 2001) (49) - - -
---- --- ---- --------- ----- - ------ -
(49) -
---- -
Comprehensive income $287 $53 $490
==== = === ====
Balance at December 31 (113) 139 336
------- ---- --- - ---
Common Stock:
Balance at January 1 1,043 1,043 1,043
Shares issued 488 -
-
Shares repurchased -
--------- ---- ------- -
- (488)
- -----
Balance at December 31 1,043 1,043 1,043
-- ----- -- ----- - -----
Total Common Equity $2,194 $2,032 $2,099
====== ====== ======
During 2001, $354 million was reclassified from unrealized gains (losses)
on securities into net income as a result of the exchange of (available for
sale) shares of Powertel, Inc., for shares for Deutsche Telekom AG. Also in
2001, $(36) million was reclassified from unrealized gains (losses) on
securities into net income as a result of the recording of an impairment of the
ITC^DeltaCom, Inc. investment.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
SCANA Corporation (the Company), a South Carolina corporation, is a
registered public utility holding company within the meaning of the Public
Utility Holding Company Act of 1935, as amended (PUHCA). The Company, through
wholly owned subsidiaries, is engaged predominately 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 is also
engaged in other energy-related businesses, has investments in
telecommunications companies and provides fiber optic communications in South
Carolina.
The accompanying Consolidated Financial Statements reflect the accounts
of the Company and its wholly owned subsidiaries:
Regulated utilities 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.
South Carolina Pipeline Corporation (SCPC) Primesouth, Inc.
Public Service Company of North Carolina, SCANA Resources, Inc.
Incorporated (PSNC) SCG Pipeline, Inc.
SCANA Services, Inc.
SCANA Propane Gas, Inc.
(in liquidation)
SCANA Propane Services, Inc.
(in liquidation)
SCANA Petroleum Resources, Inc.
(in liquidation)
SCANA Development Corporation
(in liquidation)
Certain investments are reported 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. This accounting
standard requires cost-based rate-regulated utilities to recognize in their
financial statements revenues and expenses in different time periods than do
enterprises that are not rate-regulated. As a result the Company has recorded,
as of December 31, 2001, approximately $244 million and $100 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $142 million and $76
million, respectively. The electric and gas regulatory assets of approximately
$52 million and $50 million, respectively (excluding deferred income tax
assets), are recoverable through rates. The Public Service Commission of South
Carolina (SCPSC) and the North Carolina Utilities Commission (NCUC) have
reviewed and approved most of the items shown as regulatory assets through
specific orders. Other items represent costs which were not yet approved for
recovery by the SCPSC or the NCUC, but are the subject of current or future
filings. In recording these costs as regulatory assets, management believes the
costs will be allowable under existing rate-making concepts that are embodied in
current rate orders received by the Company. However, ultimate recovery is
subject to SCPSC or NCUC 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 in the period the
write-off would be recorded, but it is not expected that cash flows or financial
position would be materially affected.
C. System of Accounts
The accounting records of the Company's regulated subsidiaries are
maintained in accordance with the Uniform System of Accounts prescribed by
either the Federal Energy Regulatory Commission (FERC) or the National
Association of Regulatory Utility Commissioners (NARUC) and as adopted by the
SCPSC or, in the case of PSNC, the NCUC. The NARUC system of accounts is
substantially the same as the FERC system of accounts.
D. Utility Plant
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, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
SCE&G, operator of the V. C. Summer Nuclear Station (Summer Station),
and the South Carolina Public Service Authority (Santee Cooper) are joint owners
of 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 approximately $963.0 million
and $965.0 million as of December 31, 2001 and 2000, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was approximately
$407.4 million and $387.7 million as of December 31, 2001 and 2000,
respectively. SCE&G's share of the direct expenses associated with operating
Summer Station is included in "Other operation and maintenance" expenses.
As allowed by the SCPSC, SCE&G accrues in advance its portion of
estimated scheduled outage costs for Summer Station. Total outage costs for the
planned outage in April 2002 are estimated to be approximately $13 million, of
which SCE&G will be responsible for approximately $8.9 million. As of December
31, 2001, SCE&G had accrued $5.9 million.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, 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 8.8%, 8.3% and 8.1% for 2001, 2000 and 1999, respectively. These rates
do not exceed the maximum allowable rate as calculated under FERC Order No. 561.
Interest on nuclear fuel in process is capitalized at the actual interest amount
incurred.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services
are provided to customers and include estimated amounts for electricity and
natural gas delivered, but not yet billed. Prior to January 1, 2000 revenues
related to regulated electric and gas services were recorded only as customers
were billed (see Note 2). Unbilled revenues totaled approximately $81.5 million
and $159.3 million as of December 31, 2001 and 2000, respectively.
Fuel costs for electric generation are collected through the fuel cost
component in retail electric rates. The fuel cost component contained in
electric rates 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 fuel cost hearing. SCE&G had undercollected through the
electric fuel cost component approximately $47.4 million and $35.5 million at
December 31, 2001 and 2000, respectively, which are included in "Deferred Debits
- - 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 gas
cost recovery hearing. At December 31, 2001 and 2000 SCE&G had undercollected
through the gas cost recovery procedure approximately $12.2 million and $12.7
million, respectively, which are included in "Deferred Debits - Other regulatory
assets." At December 31, 2001 PSNC had overcollected through the gas cost
recovery procedure approximately $13.8 million which amount is included in
"Deferred Credits - Other regulatory liabilities." At December 31, 2000 PSNC had
undercollected through the gas cost recovery procedure approximately $9.3
million which amount is included in "Deferred Debits - Other regulatory assets."
SCE&G's and PSNC'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.
G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the
straight-line method and are 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:
2001 2000 1999
- ------------------------------------- -------------- ---------------
SCE&G 2.98% 2.98% 2.99%
GENCO 2.71% 2.67% 2.56%
SCPC 2.60% 2.58% 2.62%
PSNC 4.06% 4.15% n/a
Aggregate of Above 3.09% 3.09% 2.95%
Nuclear fuel amortization, which is included in "Fuel used in electric
generation" and recovered through the fuel cost component of SCE&G's rates, is
recorded using the units-of-production method. 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 acquisition adjustment relating to the purchase of certain gas
properties in 1982 is being amortized over a 40-year period using the
straight-line method. The acquisition adjustment related to the purchase of PSNC
in 2000 is being amortized over a 35-year period using the straight-line method.
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," on January
1, 2002. See Note 1N for further discussion.
H. Nuclear Decommissioning
SCE&G's share of estimated site-specific nuclear decommissioning costs
for Summer Station, including the cost of decommissioning plant components not
subject to radioactive contamination, totals approximately $357.3 million,
stated in 1999 dollars, based on a decommissioning study completed in 2000.
Santee Cooper is responsible for decommissioning costs related to its one-third
ownership interest in the station. The cost estimate is based on a
decommissioning methodology acceptable to the Nuclear Regulatory Commission
(NRC) under which the site would be maintained over a period of approximately 60
years in such a manner as to allow for subsequent decontamination that permits
release for unrestricted use.
SCE&G's method of funding decommissioning costs is referred to as COMReP
(Cost of Money Reduction Plan). Under this plan, funds collected through rates
($3.2 million in each of 2001, 2000 and 1999) are used to pay premiums on
insurance policies on the lives of certain Company personnel. SCE&G is the
beneficiary of these policies. Through these insurance contracts, SCE&G is able
to take advantage of income tax benefits and accrue earnings on the fund on a
tax-deferred basis. Amounts for decommissioning collected through electric
rates, insurance proceeds, and interest on proceeds, less expenses, are
transferred by SCE&G to an external trust fund in compliance with the financial
assurance requirements of the NRC. Management intends for the fund, including
earnings thereon, to provide for all eventual decommissioning expenditures on an
after-tax basis. SCE&G records its liability for decommissioning costs in
deferred credits.
In addition to the above, pursuant to the National Energy Policy Act
passed by Congress in 1992 and the requirements of the DOE, SCE&G has recorded a
liability for its estimated share of the DOE's decontamination and
decommissioning obligation. The liability, approximately $2.4 million at
December 31, 2001, has been included in "Long-Term Debt, net." SCE&G is
recovering the cost associated with this liability through the fuel cost
component of its rates; accordingly, this amount has been deferred and is
included in "Deferred Debits - Other."
I. Income Taxes
The Company files a consolidated 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 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.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium, discount and expense are being amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues. Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.
K. 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 primarily to regulated operations. Such amounts are deferred
and amortized with recovery provided through rates. Deferred amounts for SCE&G,
net of amounts previously recovered through rates and insurance settlements,
totaled $24.4 million and $20.2 million at December 31, 2001 and 2000,
respectively. Deferred amounts for PSNC totaled $9.1 million and $10.2 million
at December 31, 2001 and 2000, respectively. The deferral includes the estimated
costs associated with the matters discussed in Note 13C.
L. Temporary Cash Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments are generally in the form of commercial paper, certificates of
deposit and repurchase agreements.
M. Commodity Derivatives
Beginning January 1, 2001 the Company recognizes assets or liabilities
for the energy-related contracts entered into by its subsidiaries when the
contracts are executed. The Company records contracts at their fair value in
accordance with SFAS 133 and adjusts fair value each reporting period. The
Company derives fair value of most of the energy-related contracts from markets
where they are actively traded and quoted. For other 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
contracts maturing in two years or less. The vast majority of the Company's
contracts do not extend beyond two years. (See Note 12). For such transactions
related to the Company's regulated operations, gains and losses on these
contracts are included as a component of the related cost of gas which is
subject to recovery under the fuel adjustment clause. (See Note 1F). The
resulting under or over recovery of such costs is recorded in "Deferred Debits"
or "Deferred Credits," respectively, on the balance sheet.
N. New Accounting Standards
In 2001 the Financial Accounting Standards Board issued the following
new accounting standards that will be adopted by the Company.
SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other
Intangible Assets," were issued during 2001. SFAS 141 will require all future
acquisitions to be accounted for utilizing the purchase method. SCANA considers
the amounts categorized by FERC as "acquisition adjustments" to be goodwill as
defined in SFAS 142 and has ceased amortization of such amounts upon the
adoption of SFAS 142 effective January 1, 2002. In 2001, the amount of such
amortization expense recorded was $14 million. This amortization related to
acquisition adjustments of approximately $466 million carried on the books of
PSNC and approximately $40 million carried on the books of SCPC.
As required by the provisions of SFAS 142, the Company is performing
initial valuation analyses to determine whether these carrying amounts are
impaired, and if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement, the Company will have completed the initial stage of those analyses
by June 30, 2002. If any write-downs are indicated by those analyses, they will
be quantified and recorded by the end of 2002. Because the Company is in the
early stages of these analyses, the effect, if any, of the adoption of the
impairment provisions of the Statement is not known; however, if write-downs are
considered necessary, they could be material to the Company's results of
operations for 2002.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," are effective January 1, 2002. This Statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
O. Stock Option Plan
On April 27, 2000 the Company adopted the SCANA Corporation Long-Term
Equity Compensation Plan (the Plan). Under the Plan certain employees and
non-employee directors may receive nonqualified stock options and other forms of
equity compensation. The Company accounts for this equity-based compensation
under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees" (APB 25), and related interpretations. In addition, the Company
has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based
Compensation."
P. 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 as net
income divided 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.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2001.
R. 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. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues associated with its regulated utility operations from
cycle billing to full accrual. The cumulative effect of this change was $29
million, net of tax. Accruing unbilled revenues more closely matches revenues
and expenses. Unbilled revenues represent the estimated amount customers will be
charged for service rendered but not yet billed as of the end of the accounting
period.
If this method had been applied retroactively, net income would have
been $181 million ($1.75 per share) for the year ended December 31, 1999
compared to $179 million ($1.73 per share) as reported.
3. ACQUISITION
Effective January 1, 2000 the Company acquired PSNC in a business
combination accounted for as a purchase. PSNC is a public utility engaged
primarily in purchasing, transporting, distributing and selling natural gas to
approximately 379,000 residential, commercial and industrial customers in 26 of
its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan
of Merger, PSNC shareholders were paid approximately $212 million in cash and
17.4 million shares of SCANA common stock valued at approximately $488 million.
In connection with the acquisition, 16.3 million shares of SCANA common stock
were repurchased for approximately $488 million. The results of operations of
PSNC are included in the accompanying financial statements as of January 1,
2000, the effective date of acquisition. The total cost of the acquisition was
approximately $700 million, which exceeded the fair value of the net assets
acquired by approximately $466 million. The excess is being amortized over 35
years on a straight-line basis.
The following represents the unaudited pro forma results of operations
of the Company for 1999 as if the acquisition were consummated on January 1,
1999. The unaudited pro forma results of operations exclude the effects of the
accounting change discussed in Note 2 and include certain pro forma adjustments,
including the amortization of the acquisition adjustment and interest on
acquisition financing. The unaudited pro forma results of operations do not
necessarily reflect the results that would have occurred had the acquisition
occurred at January 1, 1999 or the results that may occur in the future.
In millions of dollars, except per share amount
----------------------------------------------------------- ----------
Operating revenues $2,385
Net income 163
Basic and diluted earnings per share 1.56
4. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company
Electric
On April 24, 2001 the SCPSC approved SCE&G's request to increase the
fuel component of rates charged to electric customers from 1.330 cents per
kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2001 through April 2002. The increase
also provides recovery over a two-year period of under-collected actual fuel
costs through April 2001, including short-term purchased power costs
necessitated by outages at two of SCE&G's base load generating plants in winter
2000-2001. The new rates were effective as of the first billing cycle in May
2001.
On September 14, 1999 the SCPSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan was implemented beginning
January 1, 2000 for a three-year period. The SCPSC approved an accelerated
capital recovery methodology wherein SCE&G may increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year. As of December 31, 2001
no accelerated depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
On January 9, 1996 the SCPSC authorized a return on common equity of
12.0 percent. The SCPSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a ten-year
period. Additionally, the SCPSC approved accelerated amortization of a
significant portion of SCE&G's electric regulatory assets (excluding deferred
income tax assets) and the remaining transition obligation for postretirement
benefits other than pensions, which enabled SCE&G to recover the balances as of
the end of the year 2000.
Gas
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 component in effect during the years ended December
31, 2001and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.993 January-February 2001 $.543 January-July 2000
$.793 March-October 2001 $.688 August-October 2000
$.596 November-December 2001 $.782 November-December 2000
On July 5, 2000 the SCPSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million. The retroactive effect was
recorded in the second quarter of 2000.
In 1994 the SCPSC issued an order approving SCE&G's request to recover
through a billing surcharge to its gas customers the costs of environmental
cleanup at the sites of former manufactured gas plants (MGPs). The billing
surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for SCE&G's gas operations that had previously
been deferred. In October 2001, as a result of the annual review, the SCPSC
approved SCE&G's request to increase the billing surcharge from 1.1 cents per
therm to 3.0 cents per therm, which is intended to provide for the recovery of
the balance remaining at December 31, 2001 of $24.4 million prior to the end of
the year 2005.
Transit
In September 1992 the SCPSC issued an order granting SCE&G's request for
a $.25 increase in transit fares from $.50 to $.75 in Columbia, South Carolina;
however, the SCPSC also required $.40 fares for low income customers and denied
SCE&G's request for certain bus route and schedule changes. The new rates were
placed into effect in October 1992. After several appeals and petitions for
reconsideration to the South Carolina Circuit Court (Circuit Court) and the
South Carolina Supreme Court (Supreme Court) by the various parties, on
September 27, 2000 the SCPSC issued an order granting certain relief requested
by SCE&G. On September 29, 2000 the Consumer Advocate of South Carolina
(Consumer Advocate) filed a motion with the SCPSC for a stay of this order. On
October 3, 2000 the SCPSC accepted the Consumer Advocate's motion and issued a
stay of its order. The Consumer Advocate and other intervenors have petitioned
the Circuit Court for judicial review of the SCPSC's order granting relief. The
Circuit Court has held in abeyance any appellate review pending the outcome of
current negotiations on the transfer of the transit system from SCE&G to an
unaffiliated regional transit authority.
Public Service Company of North Carolina, Incorporated
PSNC'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 and changes in the rates charged by PSNC's pipeline
transporters. PSNC may file revised tariffs with the NCUC coincident with these
changes or it may track the changes in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC's gas purchasing practices annually.
PSNC's benchmark cost of gas in effect during the years ended December
2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2000
$.750 February-March 2001 $.265 February-May 2000
$.650 April-August 2001 $.350 June 2000
$.500 September-October 2001 $.450 July-September 2000
$.350 November-December 2001 $.490 October-December 2000
On April 6, 2000 the NCUC issued an order permanently approving PSNC's
request to establish its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas. This
mechanism allows PSNC to collect from its customers amounts approximating the
amounts paid for natural gas.
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. On June 29, 2000 the NCUC approved PSNC's
requests for disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million. The Madison County portion of the project was completed at a cost
of approximately $5.8 million, and customers began receiving service in July
2001.
On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of PSNC. As specified in the NCUC order, PSNC reduced its rates by
approximately $1 million in each of August 2000 and August 2001, and agreed to a
moratorium on general rate cases until August 2005. General rate relief can be
obtained during this period to recover costs associated with materially adverse
governmental actions and force majeure events.
On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County and
authorized disbursements from the fund of approximately $4.3 million . Most of
Alexander County lies within PSNC's certificated service territory and did not
previously have natural gas service. The project was completed at a cost of
approximately $4.8 million, and customers began receiving natural gas service in
March 2000.
5. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Employee Benefit Plans
The Company sponsors a 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 the applicable Federal income
tax regulations as determined by an independent actuary.
Effective July 1, 2000 the Company's pension plan was amended to provide
a cash balance formula. With certain exceptions employees were allowed to either
remain under the final average pay formula or elect the cash balance formula.
Under the final average pay formula, benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment. Under the cash balance formula, the monthly benefit
earned under the final average pay formula at July 1, 2000 was converted to a
lump sum amount for each employee and increased by transition credits for
eligible employees. Under the cash balance formula, benefits based upon this
opening balance increase going forward as a result of compensation credits and
interest credits. The effect of this plan amendment was to reduce the Company's
net periodic benefit income for the year ended December 31, 2000 by
approximately $3.7 million.
In addition to pension benefits, the Company provides certain unfunded
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 the applicable benefits.
Effective July 1, 2000 PSNC's pension and postretirement benefit plans
were merged with SCANA's plans. At the time of the merger of the plans, PSNC had
recorded a prepaid pension cost of approximately $9.0 million and a
postretirement welfare plan obligation of approximately $9.1 million in its
consolidated balance sheet.
In connection with the joint ownership arrangements surrounding Summer
Station, as of December 31, 2001 the Company has recorded within deferred
credits an $8.4 million obligation to Santee Cooper, representing an estimate of
the net pension asset attributable to the Company's contributions to the plan
that were recovered through billings to Santee Cooper for its one-third portion
of shared costs. The Company has also recorded a $6.0 million receivable from
Santee Cooper, representing an estimate of its portion of the unfunded net
postretirement benefit obligation.
As allowed by SFAS 87, 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," are set forth in the following tables:
Components of Net Periodic Benefit Cost
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
Millions of dollars 2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Service cost $7.9 $ 8.3 $10.0 $3.0 $ 2.7 $ 3.0
Interest cost 38.5 33.5 27.9 12.1 10.2 9.5
Expected return on assets (83.5) (76.6) (65.5) n/a n/a n/a
Prior service cost amortization 5.8 3.0 1.1 0.9 0.8 0.7
Actuarial (gain) loss (12.8) (12.2) (8.6) 0.7 - 1.2
Transition amount amortization 0.8 0.8 0.8 0.8 0.8 1.7
Special termination benefit cost - 5.5 - - 1.0
------- -- ----- --- -------- - -------- ---- ---
-
Net periodic benefit (income) $(43.3) $(43.2) $(28.8) $17.5 $14.5 $17.1
====== ====== ====== ===== ===== =====
cost
Assumptions
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
As of December 31, 2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Discount rate 7.5% 8.0% 8.0% 7.5% 8.0% 8.0%
Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Changes in Benefit Obligation
Retirement Benefits Other Postretirement Benefits
------------------------------ ---------------------------------
Millions of dollars 2001 2000 2001 2000
---- ---- ---- ----
Benefit obligation, January 1 $479.3 $362.3 $139.0 $129.8
Service cost 7.9 8.3 3.0 2.7
Interest cost 38.5 33.5 12.1 10.2
Plan participants' contributions - 0.1 0.5 0.5
Plan amendment 21.5 65.4 1.2 0.9
Actuarial (gain) loss 19.6 1.6 20.1 (7.8)
Acquisition/merger of plans - 39.8 - 11.2
Benefits paid (36.0) (31.7) (9.2) (8.5)
-- ----- --- ----- ---- ---- ---- ----
Benefit obligation, December 31 $530.8 $479.3 $166.7 $139.0
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
----------------------------------------------------
Millions of dollars 2001 2000
---- ----
Fair value of plan assets, January 1 $894.3 $783.0
Actual return on plan assets (26.7) 96.7
Company contribution - -
Plan participants' contributions - 0.1
Acquisition/merger of plans - 46.2
Benefits paid (36.0) (31.7)
-- ----- --- -----
Fair value of plan assets, December 31 $831.6 $894.3
====== = ======
Funded Status of Plans
Retirement Benefits Other Postretirement Benefits
------------------------ -------------------------------
Millions of dollars 2001 2000 2001 2000
---- ---- ---- ----
Funded status, December 31 $300.8 $415.0 $(166.7) $(139.0)
Unrecognized actuarial (gain) loss (155.0) (297.6) 32.5 13.0
Unrecognized prior service cost 89.4 73.7 4.8 4.5
Unrecognized net transition obligation 4.0 4.8 7.4 8.3
--------- ---------- -------- --- ----- ---
Net amount recognized in Consolidated Balance Sheet $239.2 $195.9 $(122.0) $(113.2)
====== = ====== ======= =======
Health Care Trends
The determination of net periodic other postretirement benefit cost is based on
the following assumptions:
2001 2000 1999
--------------------------------------------------- ---------- ----------
Health care cost trend rate 8.5% 7.5% 8.0%
Ultimate health care cost trend rate 5.0% 5.5% 5.5%
Year achieved 2009 2005 2005
The effects of a one-percentage-point increase or decrease in the assumed
health care cost trend rates on the aggregate of the service and interest cost
components of net periodic other postretirement health care benefit cost and the
accumulated other postretirement benefit obligation for health care benefits are
as follows:
Millions of dollars 1% 1%
Increase Decrease
--------------- -----------------
Effect on health care benefit cost $0.1 $(0.1)
Effect on postretirement benefit obligation 1.6 (1.8)
Long-Term Equity Compensation Plan
The Long-Term Equity Compensation Plan (the Plan) became effective January
1, 2000. The Plan provides for grants of incentive and 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.
A summary of activity related to grants of nonqualified stock options
follows:
Weighted
Number of Average
Options Exercise Price
------------------------------------------------------- --------------------
Outstanding - December 31, 1999 - -
Granted 160,508 $25.53
-------------------------------------------------------
Outstanding - December 31, 2000 160,508 $25.53
Granted 716,368 $27.43
Exercised - n/a
Forfeited (74,595) $26.93
-------------------------------------------------------
Outstanding - December 31, 2001 802,281 $26.64
=======================================================
One-third of the options vest on each anniversary of the date of grant
until full vesting occurs in the third year. The options expire ten years after
the grant date. Information about outstanding and exercisable options as of
December 31, 2001 follows:
Options Outstanding Options Exercisable
Weighted
Range Average Weighted Weighted
of Number Remaining Average Number Average
Exercise of Contractual Exercise of Exercise
Prices Options Life (in years) Price Options Price
- ------------------ -------------------------------------------------------------
$25.50 to $27.80 802,281 9.2 $26.64 47,275 $25.53
- ------------------ -------------------------------------------------------------
The Company applies the intrinsic value method prescribed by APB 25 and
related interpretations in accounting for grants made under the Plan. Because
all options were granted with exercise prices equal to the fair market value of
the Company's stock on the respective grant dates, no compensation expense has
been recognized in connection with such grants. If the Company had determined
compensation expense for the issuance of options based on the fair value method
described in SFAS 123, "Accounting for Stock-Based Compensation," pro forma net
income and earnings per share would have been as presented below:
2001 2000
---- ----
Net income - as reported (millions) $539.3 $250.4
Net income - pro forma (millions) 538.5 250.3
Basic and diluted earnings per share - as reported 5.15 2.40
Basic and diluted earnings per share - pro forma 5.14 2.40
For purposes of the above pro forma information, the weighted average
fair value at grant date (the value at grant date of the right to purchase stock
at a fixed price for an extended time period) for options granted in 2001 and
2000 was $5.13 and $4.43, respectively, and was estimated using the
Black-Scholes Option pricing model with the following weighted average
assumptions.
2001 2000
---- ----
Expected life of options (years) 7 10
Risk free interest rate 5.08% 5.99%
Volatility of underlying stock 22% 21%
Dividend yield of underlying stock 4.2% 4.4%
6. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2002 through 2006 are summarized as follows:
Year Amount Year Amount
- --------------- ----------------- ------------------ -----------------
(Millions of dollars)
2002 $738.3 2005 $182.0
2003 500.3 2006 162.8
2004 187.0
- --------------- ----------------- ------------------ -----------------
Approximately $23.5 million of the portion of long-term debt payable in
2002 may be satisfied by either deposit and cancellation of bonds issued upon
the basis of property additions or bond retirement credits, or by deposit of
cash with the Trustee.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with SCE&G. In consideration for the electric franchise
agreement, SCE&G is paying the City $25 million over seven years (1996-2002) and
has donated to the City the existing transit assets in Charleston. The $25
million is included in electric plant-in-service.
SCE&G has three-year revolving lines of credit totaling $75 million, in
addition to other lines of credit, that provide liquidity for issuance of
commercial paper. The three-year lines of credit provide back-up liquidity when
commercial paper outstanding is in excess of $175 million. SCE&G's commercial
paper outstanding totaled $114.7 million and $117.5 million at December 31, 2001
and 2000, at weighted average interest rates of 1.95 percent and 6.59 percent,
respectively.
Substantially all utility plant is pledged as collateral in connection
with long-term debt.
On January 31, 2002 SCANA issued $250 million medium-term notes maturing
February 1, 2012 and bearing a fixed interest rate of 6.25 percent. Also on
January 31, 2002 SCANA issued $150 million two-year floating rate notes maturing
on February 1, 2004. The interest rate on the floating rate notes is reset
quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from these
issuances were used to refinance $400 million of two-year floating rate notes
that matured on February 8, 2002, which had been issued to finance SCANA's
acquisition of PSNC.
On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1, 2032.
The proceeds from the sale of these bonds were used to reduce short-term debt
primarily incurred as a result of SCE&G's construction program and to redeem its
First and Refunding Mortgage Bonds, 8 7/8 percent Series due August 15, 2021.
7. FUEL FINANCINGS
Nuclear and fossil fuel inventories and sulfur dioxide emission
allowances are financed through the issuance by Fuel Company of short-term
commercial paper. These short-term borrowings are supported by a 364-day
revolving credit agreement which expires December 17, 2002. The credit agreement
provides for a maximum amount of $125 million to be outstanding at any time.
Since the credit agreement expires within one year, commercial paper amounts
outstanding have been classified as short-term debt.
Fuel Company commercial paper outstanding totaled $50.1 million and
$70.2 million at December 31, 2001 and 2000, respectively, at weighted average
interest rates of 2.06 percent and 6.59 percent, respectively.
8. SHORT-TERM BORROWINGS
Details of lines of credit (including uncommitted lines of credit) and
short-term borrowings at December 31, 2001 and 2000, are as follows:
Millions of dollars 2001 2000
- --------------------------------------------------------- ---------------
Authorized lines of credit $588.0 $649.0
Unused lines of credit $588.0 $564.0
Short-term borrowings outstanding
Bank loans - $85.0
Weighted average interest rate n/a 7.48%
Commercial paper (270 days or less) $164.8 $312.7
Weighted average interest rate 1.97% 6.63%
The Company pays fees to banks as compensation for its committed lines of
credit.
9. COMMON EQUITY
The Company's Restated Articles of Incorporation do not limit the
dividends that may be payable on its common stock. However, the Restated
Articles of Incorporation of SCE&G and the Indenture underlying its First and
Refunding Mortgage Bonds contain provisions that, under certain circumstances,
could limit the payment of cash dividends on its common stock. In addition, with
respect to hydroelectric projects, the Federal Power Act requires the
appropriation of a portion of certain earnings therefrom. At December 31, 2001
approximately $37 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 2001, 2000 and 1999
at an annual rate per share of $1.20, $1.15 and $1.32, respectively.
The accumulated balances related to each component of other
comprehensive income were as follows:
Unrealized Cash flow Accumulated other
- --------------------------------
ains (losses) hedging comprehensive
- --------------------------------
Million of dollars on securities activities income
- --------------------------------------------------------------------------------
- --------------------------------
Balance, January 1, 1999 $25 $25
- --------------------------------
Other comprehensive income 311 311
- --------------------------------------------------------------------------------
Balance, December 31, 1999 336 336
- --------------------------------
Other comprehensive loss (197) (197)
- --------------------------------------------------------------------------------
Balance, December 31, 2000 139 139
- --------------------------------
Other comprehensive loss (226) $(26) (252)
- --------------------------------
- --------------------------------------------------------------------------------
Balance, December 31, 2001 $(87) $(26) $(113)
================================================================================
10. PREFERRED STOCK
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements under sinking fund
requirements are at par values. The aggregate annual amount of purchase fund or
sinking fund requirements for preferred stock for the years 2002 through 2006 is
$2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 2001, 2000 and 1999 are summarized as follows:
Number of Shares Millions of Dollars
- -------------------------------------------------------------------------------
Balance at December 31, 1998 240,052 $12.0
Shares Redeemed - $50 par value (8,565) (0.4)
- -------------------------------------------------------------------------------
Balance at December 31, 1999 231,487 11.6
Shares Redeemed - $50 par value (11,200) (0.6)
- -------------------------------------------------------------------------------
Balance at December 31, 2000 220,287 11.0
Shares Redeemed - $50 par value (10,803) (0.5)
- -------------------------------------------------------------------------------
Balance at December 31, 2001 209,484 $10.5
===============================================================================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned
subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55 percent Trust
Preferred Securities, Series A (the "Preferred Securities"). SCE&G owns all of
the Common Securities of the Trust (the "Common Securities"). The Preferred
Securities and the Common Securities (the "Trust Securities") represent
undivided beneficial ownership interests in the assets of the Trust. The Trust
exists for the sole purpose of issuing the Trust Securities and using the
proceeds thereof to purchase from SCE&G its 7.55 percent Junior Subordinated
Debentures due September 30, 2027. The sole asset of the Trust is $50.0 million
of Junior Subordinated Debentures of SCE&G. Accordingly no financial statements
of the Trust are presented. The financial statements of the Trust are
consolidated in the financial statements of SCE&G. The Guarantee Agreement
entered into in connection with the Preferred Securities, when taken together
with SCE&G's obligation to make interest and other payments on the Junior
Subordinated Debentures issued to the Trust and SCE&G's obligations under the
Indenture pursuant to which the Junior Subordinated Debentures were issued,
provides a full and unconditional guarantee by SCE&G of the Trust's obligations
under the Preferred Securities. Proceeds were used to redeem preferred stock of
SCE&G.
The preferred securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55 percent Junior Subordinated Debentures.
The Junior Subordinated Debentures will mature on September 30, 2027 and may be
redeemed, in whole or in part, at any time on or after September 30, 2002 or
upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received
from counsel experienced in such matters that there is more than an
insubstantial risk that: (1) the Trust is or will be subject to Federal income
tax, with respect to income received or accrued on the Junior Subordinated
Debentures, (2) interest payable by SCE&G on the Junior Subordinated Debentures
will not be deductible, in whole or in part, by SCE&G for Federal income tax
purposes, or (3) the Trust will be subject to more than a de minimis amount of
other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously be applied to redeem Preferred Securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The Preferred Securities are redeemable at $25 per
preferred security plus accrued distributions.
11. INCOME TAXES
Total income tax expense attributable to income (before cumulative effect
of accounting change) for 2001, 2000 and 1999 is as follows:
Millions of dollars 2001 2000 1999
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Current taxes:
Federal $91.2 $88.2 $94.5
State 11.2 9.2 0.6
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Total current taxes 102.4 97.4 95.1
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Deferred taxes, net:
Federal 182.5 29.8 6.1
State 1.7 4.7 1.5
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Total deferred taxes 184.2 34.5 7.6
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Investment tax credits:
Deferred - State 5.0 5.0 13.4
Amortization of amounts deferred - State (1.5) (1.3) (1.2)
Amortization of amounts deferred - Federal (4.0) (4.0) (3.6)
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Total investment tax credits (0.5) (0.3) 8.6
- ------------------------------------------------------------------- ----------------- ----------------- -----------------
Non-conventional fuel tax credits:
Deferred - Federal 18.7 9.4 n/a
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
Total income tax expense $304.8 $141.0 $111.3
=================================================================== ================= ================== ================
The difference between actual income tax expense and the amount calculated
from the application of the statutory 35 percent Federal income tax rate to
pre-tax income (before cumulative effect of accounting change) is reconciled as
follows:
Millions of dollars 2001 2000 1999
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
Income before cumulative effect of accounting change $539.3 $221.2 $178.9
Total income tax expense:
Charged to operating expense 135.2 152.0 112.9
Charged (credited) to other items 169.7 (11.0) (1.6)
Preferred stock dividends 11.2 11.2 11.2
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
Total pre-tax income $855.4 $373.4 $301.4
=================================================================== ================= ================== ================
=================================================================== ================= ================== ================
Income taxes on above at statutory Federal income tax rate $299.4 $130.7 $105.5
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 10.7 11.4 9.3
Non-deductible book amortization of acquisition adjustments 5.0 5.0 0.4
Amortization of Federal investment tax credits (4.0) (4.0) (3.6)
Other differences, net (6.3) (2.1) (0.3)
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
- ------------------------------------------------------------------- ----------------- ------------------ ----------------
Total income tax expense $304.8 $141.0 $111.3
=================================================================== ================= ================== ================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $873.9 million at December 31, 2001 and
$819.2 million at December 31, 2000 (see Note 1I), are as follows:
Millions of dollars 2001 2000
- ------------------------------------------------------ ------------------
Deferred tax assets:
Nondeductible reserves $69.7 $59.3
Unamortized investment tax credits 62.1 63.0
Deferred compensation 23.1 23.4
Cycle billing 10.6 -
Other 14.4 8.7
- ------------------------------------------------------ ------------------
Total deferred tax assets 179.9 154.4
- ------------------------------------------------------ ------------------
Deferred tax liabilities:
Property, plant and equipment 814.3 792.3
Investments in equity securities 133.3 80.0
Pension plan benefit income 81.1 65.3
Deferred fuel costs 22.8 18.5
Cycle billing - 1.9
Other 2.3 15.6
- ------------------------------------------------------ ------------------
Total deferred tax liabilities 1,053.8 973.6
- ------------------------------------------------------ ------------------
Net deferred tax liability $873.9 $819.2
====================================================== ==================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of the Company through 1995, has examined and proposed
adjustments to the Company's 1996 and 1997 Federal returns, and is currently
examining the Company's Federal returns for 1998, 1999 and 2000. The Company
does not anticipate that any adjustments which might result from these
examinations will have a significant impact on its results of operations, cash
flows or financial position.
12. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2001 and 2000 are as follows:
Millions of dollars 2001 2000
- --------------------------------------------------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
Assets:
Cash and temporary cash investments $212.0 $212.0 $158.7 $158.7
Investments 855.1 944.3 681.7 1,234.5
Liabilities:
Short-term borrowings 164.8 164.8 397.7 397.7
Long-term debt 3,384.8 3,501.0 2,890.5 2,931.9
Preferred stock (subject to
purchase or sinking funds) 10.4 8.5 11.0 8.7
The following methods and assumptions were used to estimate the fair
value of the above classes of financial instruments:
o Cash and temporary cash investments, including commercial paper,
repurchase agreements, treasury bills and notes, are valued at
their carrying amount.
o Fair values of investments and long-term debt are based on quoted
market prices of the instruments or similar instruments. For debt
instruments for which there are no quoted market prices
available, fair values are based on net present value
calculations. For investments for which the fair value is not
readily determinable, fair value is considered to approximate
carrying value. The carrying values reflect the fair values of
interest rate swaps based on settlement values obtained from
counterparties. Settlement of long-term debt may not be possible
or may not be considered prudent.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking funds) is
estimated on the basis of market prices.
o Potential taxes and other expenses that would be incurred in an
actual sale or settlement have not been taken into consideration.
Investments
SCANA and certain of its subsidiaries hold investments in marketable
securities, some of which are subject to SFAS 115 mark-to-market accounting and
some of which are considered cost basis investments for which determination of
fair value historically has been considered impracticable. Equity holdings
subject to SFAS 115 are categorized as "available for sale" and are carried at
quoted market, with any unrealized gains and losses credited or charged to other
comprehensive income within common equity on the Company's balance sheet. Debt
securities are categorized as "held to maturity" and are carried at amortized
cost. When indicated, and in accordance with its stated accounting policy, SCANA
performs periodic assessments of whether any decline in the value of these
securities to amounts below SCANA'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.
At December 31, 2001 SCANA and SCANA Communications Holdings, Inc.
(SCH), a wholly owned, indirect subsidiary of SCANA, held marketable equity and
debt securities in the following companies in the amounts noted in the table
below.
Unrealized
Investee Held By Securities (a) Basis Market (b) Gain/(Loss) (c)
- ------------------------------ --------------------------------------------------------- ---------- ------------ ----------------
(Millions of dollars)
DTAG SCH 39.3 million ordinary shares $798.0 $664.3 ($133.7)
ITC SCH 3.1 million common stock 5.8 (d) n/a
SCH 645,153 series A convertible preferred stock 7.2 (d) n/a
SCH 133,664 series B convertible preferred stock 4.0 (d) n/a
ITC^DeltaCom SCH 5.1 million common stock 4.4 (e) 4.4 -
SCH 1.5 million series A convertible preferred stock,
convertible
March 2002 2.6 (e) 2.6 -
SCANA 5,113 series B-1 preferred stock convertible into
877,193
shares of common stock 0.8 (e) 0.8 -
SCANA 6,667 series B-2 preferred stock convertible into
2,604,297
shares of common stock 2.3 (e) 2.3 -
SCANA Warrants to purchase approximately 1.0 million shares of
common stock 0.8 (e) 0.8 -
Knology SCH 7.2 million series A preferred stock, convertible 5.0 (d) n/a
upon an initial public offering
SCH Warrants to purchase 159,000 shares of series A
convertible
preferred stock, convertible upon an initial public (d) n/a
offering
SCH 8.3 million series C preferred stock, convertible 25.0 (d) n/a
upon an initial public offering
Knology
Broadband SCH $71,050,000 face amount, 11.875% Senior Discount
Notes due 2007 64.9 (d) n/a
(a) Convertible preferred stock is convertible into common stock at any time
nless otherwise indicated.
(b) As converted, based on market value of underlying common stock, where
applicable.
(c) Amounts are included in accumulated other comprehensive income (loss),
net of taxes.
(d) Market value not readily determinable.
(e) Reflects write-down for "other than temporary" impairment as discussed
below.
Deutsche Telekom AG (DTAG) is an international telecommunications carrier.
The Company's investment in DTAG was received in exchange for approximately 14.9
million shares of Powertel, Inc. (Powertel) which SCH owned prior to DTAG's
acquisition of Powertel in May 2001. SCH recorded a non-cash, after-tax gain of
$354.4 million as a result of the exchange.
ITC Holding Company (ITC) holds ownership interests in several Southeastern
communications companies. ITC^DeltaCom, Inc. (ITCD) is a fiber optic
telecommunications provider and an affiliate of ITC. Knology, Inc. (Knology) is
a broadband service provider of cable television, telephone and internet
services. Knology is an affiliate of ITC. Knology Broadband, Inc. (Knology
Broadband) is a wholly-owned subsidiary of Knology and an affiliate of ITC.
In the fourth quarter of 2001 the Company determined that the decline in
value of its investment in ITC^DeltaCom (to below cost) was other than
temporary. Accordingly the Company recorded an impairment charge of
approximately $35.0 million (after-tax).
Derivatives
Through December 31, 2000 the Company accounted for the results of its
derivative activities for hedging purposes in accordance with SFAS 80. Effective
January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. SFAS 133 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, depending upon the intended use of the derivative
and the resulting designation.
The fair value of the derivative instruments is determined by reference
to quoted market prices of listed contracts, published quotations or quotations
from independent parties.
Risk limits are established to control the level of market, credit,
liquidity and operational/administrative risks assumed by the Company. The
Company's Board of Directors has delegated the authority for setting market risk
limits to the Risk Management Committee, which is comprised of members of senior
management, the Company's Controller, the Senior Vice President of SCPC and the
President of SCANA Energy Marketing, Inc. The Risk Management Committee provides
assurance to the Board of Directors with regard to compliance with risk
management policies 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 those
transactions that are allowed.
Commodities
The Company uses derivative instruments to hedge anticipated future
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 price 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 futures contracts or options and over-the-counter
instruments such as swaps, which are typically offered by energy and financial
institutions.
As a result of adopting SFAS 133, the Company recorded a credit of
approximately $23.0 million, net of tax, as the effect of a change in accounting
principle (transition adjustment) to other comprehensive income on January 1,
2001. This amount represents the reclassification of unrealized gains that were
deferred and reported as liabilities at December 31, 2000. Substantially all of
this amount was reclassified into earnings in 2001 as a component of gas cost.
The Company recognized losses of approximately $(17.1) million, net of
tax (net of the gains discussed above), as a result of qualifying cash flow
hedges whose hedged transactions occurred during the year ended December 31,
2001. These losses were recorded in cost of gas. Losses due to hedge
ineffectiveness were insignificant. The Company estimates that substantially all
of the December 31, 2001 balance of $(26) million, net of tax, will be
reclassified from accumulated other comprehensive income to earnings in 2002 as
increased gas cost. As of December 31, 2001, all of the Company's cash flow
hedges would be settled before the end of 2003.
Certain derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its fuel adjustment clauses. Accordingly, the
offset to the change in fair value of these derivatives is recorded as a
regulatory asset or liability.
The Company also utilizes certain derivative instruments that do not
qualify as hedges. The change in fair value of these derivatives is recorded in
net income, and was insignificant in 2001.
Interest Rates
In May 2001 the Company entered into an interest rate swap agreement to
pay variable rate and receive fixed rate interest payments on a notional amount
of $300 million. This swap was designated as a fair value hedge of the $300
million medium-term notes also issued in May. The swap agreement was terminated
and replaced with another swap agreement to pay variable rate and receive fixed
rate interest payments, also designated as a fair value hedge, in August 2001.
At December 31, 2001 the estimated fair value of this swap was $1.3 million. In
August 2001 the Company received $6.5 million to terminate the original swap.
This amount is being amortized to interest expense over the ten year term of the
$300 million medium-term notes.
On December 19, 2001 PSNC entered into two interest rate swap agreements
to pay variable rate and receive fixed rate interest payments on a combined
notional amount of $44.9 million. These swaps were designated as fair value
hedges of PSNC's $12.9 million, 10 percent senior debenture due 2004 and $32.0
million, 8.75 percent senior debenture due 2012.
The fair value of these interest rate swaps is reflected within other
deferred debits on the balance sheet. The corresponding hedge debt is also
marked to market on the balance sheet. The receipts or payments related to the
interest rate swaps are credited or charged to interest expense as incurred.
13. COMMITMENTS AND CONTINGENCIES
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC notified SCE&G of its agreement with SCE&G's
plan to reinforce Lake Murray Dam in order to maintain the lake in case of an
extreme earthquake. Construction for the project and related activities, which
began in the third quarter of 2001, is expected to cost $250 million and be
completed in 2005. Any costs incurred by SCE&G are expected to be recoverable
through electric rates.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability
for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 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 $58.7 million per incident, but not
more than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited (NEIL). The policies, covering
the nuclear facility for property damage, excess property damage and outage
costs, permit 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. 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.
C. Environmental
South Carolina Electric & Gas Company
In September 1992 the Environmental Protection Agency (EPA) notified
SCE&G, among others, of its potential liability for the investigation and
cleanup of the Calhoun Park area site in Charleston, South Carolina. This site
encompasses approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's decommissioned MGPs.
Field work at the site began in November 1993 and has required the submission of
several investigative reports and the implementation of several work plans. In
September 2000, SCE&G was notified by the South Carolina Department of Health
and Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that SCE&G conduct a focused Remedial Investigation/Feasibility
Study on the intermediate aquifer, which was completed in June 2001. The EPA
expects to issue a Record of Decision dealing with the intermediate aquifer and
sediments in June 2002. SCE&G anticipates that major remediation activities will
be completed in 2003, with certain monitoring activities continuing until 2007.
As of December 31, 2001, SCE&G has spent approximately $15.8 million to
remediate the Calhoun Park area site. Total remediation costs are estimated to
be $21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which
contain residues of by-product chemicals. Two of these sites are currently being
remediated under work plans approved by DHEC. SCE&G is continuing to investigate
the remaining site and is monitoring the nature and extent of residual
contamination. SCE&G anticipates that major remediation activities for these
three sites will be completed between 2003-2005. SCE&G has spent approximately
$2.0 million related to these sites, and expects to incur an additional $6.0
million.
Public Service Company of North Carolina, Incorporated
PSNC owns, or has owned, all or portions of seven sites in North Carolina
on which MGPs were formerly operated. Intrusive investigation (including
drilling, sampling and analysis) has begun at two sites and the remaining sites
have been evaluated using historical records and observations of current site
conditions. These evaluations have revealed that MGP residuals are present or
suspected at several of the sites. PSNC estimates that the cost to remediate the
sites would range between $11.3 million and $21.9 million. The estimated cost
range has not been discounted to present value. PSNC's associated actual costs
for these sites will depend on a number of factors, such as actual site
conditions, third-party claims and recoveries from other PRPs. At December 31,
2001 PSNC has recorded a liability and associated regulatory asset of $9.1
million, which reflects the minimum amount of the range, net of shared cost
recovery expected from other PRPs and expenditures for work completed. Amounts
incurred to date are approximately $1.1 million. Management believes that all
MGP cleanup costs incurred will be recoverable through gas rates.
D. Franchise Agreement
See Note 6 for a discussion of the electric franchise agreement between
SCE&G and the City of Charleston.
E. Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of the propane gas
assets of SCANA filed suit against SCANA in Circuit Court seeking unspecified
damages. The suit alleges the existence of a contract for the sale of assets to
the plaintiff and various causes of action associated with that contract. The
Company is confident in its position and intends to vigorously defend the
lawsuit. The Company does not believe that the resolution of this issue will
have a material impact on its results of operations, cash flows or financial
position.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
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
2011. Rent expense totaled approximately $12.1 million, $8.8 million and $6.7
million in 2001, 2000 and 1999, respectively. Future minimum rental payments
under such leases are as follows:
Millions of dollars
2002 $17.2
2003 14.7
2004 11.4
2005 10.3
2006 9.7
Thereafter 26.5
------
$89.8
G. Purchase Commitments
Purchase commitments including those commitments under forward contracts
for natural gas purchases, gas transportation capacity agreements and coal
supply contracts are as follows:
Millions of dollars
2002 $508.6
2003 216.4
2004 73.0
2005 15.3
2006 15.3
Thereafter 196.6
-----
$1,025.2
The forward contracts for natural gas purchases include customary
"make-whole" or default provisions, but are not considered to be "take-or-pay"
contracts.
14. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are Electric Operations, Gas
Distribution, Gas Transmission, Retail Gas Marketing, Energy Marketing and
Telecommunications Investments. 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 comprised of the electric portion of SCE&G, GENCO
and Fuel Company and is primarily engaged in the generation, transmission and
distribution of electricity. SCE&G's electric service territory extends into 24
counties covering more than 15,000 square miles in the central, southern and
southwestern portions of South Carolina. Sales of electricity to industrial,
commercial and residential customers are regulated by the SCPSC. SCE&G is also
regulated by FERC. GENCO owns and operates the Williams Station generating
facility and sells all of its electric generation to SCE&G. GENCO is regulated
by FERC. Fuel Company acquires, owns and provides financing for the fuel and
emission allowances required for the operation of SCE&G and GENCO generation
facilities.
Gas Distribution, comprised of the local distribution operations of SCE&G
and PSNC, is engaged in the purchase and sale, primarily at retail, of natural
gas. SCE&G's operations extend to 33 counties in South Carolina covering
approximately 22,000 square miles. PSNC was acquired by SCANA in 2000. PSNC's
operations cover 26 counties in North Carolina and approximately 12,000 square
miles. Gas Transmission is comprised of SCPC, which is engaged in the purchase,
transmission and sale of natural gas on a wholesale basis to distribution
companies (including SCE&G), and directly to industrial customers in 40 counties
throughout South Carolina. SCPC also owns LNG liquefaction and storage
facilities. Both of these segments are regulated in their respective states of
operations.
Retail Gas Marketing markets natural gas in Georgia's deregulated natural
gas market. Energy Marketing markets electricity and natural gas to industrial,
large commercial and wholesale customers, primarily in the Southeast.
Telecommunications Investments holds investments in telecommunication
companies.
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
primarily based on the class of customers each serves and the marketing
strategies resulting from those differences. The marketing segments are
nonregulated, but differ from each other primarily based on their respective
markets.
Disclosure of Reportable Segments
Millions of dollars
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ ---------
Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated
Gas
2001 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ ---------
External Customer Revenue $1,369 $789 $226 $628 $439 - $(49) $3,451
$49
Intersegment Revenue 576 4 253 - - - (841) -
8
Operating Income 419 75 16 n/a n/a - (4) 528
22
Interest Expense 10 22 6 6 3 $23 151 223
2
Depreciation & Amortization 160 54 7 2 1 - (6) 224
6
Income Tax Expense 3 18 4 4 1 169 102 305
4
Net Income n/a n/a n/a 8 3 314 240 539
(26)
Segment Assets 5,034 1,617 335 99 96 784 272 (415) 7,822
Expenditures for Assets 414 90 21 4 2 - - 548
17
Deferred Tax Assets 6 - 4 5 6 - (21) -
-
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ----- ------------ ----
Millions of dollars
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ------ ------------- -------
Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated
Gas
2000 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ------ ------------- -------
External Customer Revenue $1,344 $745 $253 $548 $544 - $41 $(42) $3,433
Intersegment Revenue 318 1 236 - - - 9 (564) -
Operating Income (Loss) 446 85 28 n/a n/a - - (5) 554
Interest Expense 13 20 4 5 1 $23 3 156 225
Depreciation & Amortization 155 53 7 1 - - 5 (4) 217
Income Tax Expense 1 23 8 1 (1) (4) - 113 141
(Benefit)
Net Income (Loss) n/a n/a 4 (4) (7) 1 256 250
n/a
Segment Assets 4,953 1,628 309 103 215 599 86 (466) 7,427
Expenditures for Assets 229 58 18 - - - 27 29 361
Deferred Tax Assets 6 - 3 5 4 - 1 (19) -
- ---------------------------- ---------- ----------- ------------- --------- --------------------------- ------ ------------- -------
Millions of dollars
- ---------------------------- ---------- ----------- ------------ --------- -------------------------------- ------------------------
Electric Gas Gas Retail Energy Telecommunications All Adjustments/ Consolidated
Gas
1999 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ---------------------------- ---------- ----------- ------------ --------- -------------------------------- ------------------------
External Customer Revenue $1,226 $234 $188 $207 $224 - $73 $(74) $2,078
Intersegment Revenue 308 5 154 - - - 11 (478) -
Operating Income (Loss) 390 22 20 n/a n/a - - (79) 353
Interest Expense 12 n/a 4 4 1 $1 22 98 142
Depreciation & Amortization 148 13 7 1 1 - 7 (8) 169
Income Tax Expense 1 n/a 9 (24) (2) - 21 106 111
(Benefit)
Net Income (Loss) n/a n/a n/a (45) (4) - 22 206 179
Segment Assets 4,751 399 253 (24) 168 889 43 (468) 6,011
Expenditures for Assets 201 19 8 2 1 - 6 24 261
Deferred Tax Assets 6 n/a 3 - 1 - 1 5 16
- ---------------------------- ---------- ----------- ------------ --------- --------------------------- ----- ------------ ----------
Revenues and assets from segments below the quantitative thresholds are
attributable to SCE&G's transit operations, which are regulated by the SCPSC,
and to ten other wholly owned subsidiaries of the Company. These subsidiaries
conduct nonregulated operations in energy-related and telecommunications
industries. None of these subsidiaries met any of the quantitative thresholds
for determining reportable segments in 2001, 2000 or 1999.
Management uses operating income to measure segment profitability for
regulated operations. For nonregulated operations management uses net income for
this purpose. Accordingly, SCE&G does not allocate interest charges or income
tax expense (benefit) to the Electric Operations or Gas Distribution segments.
Similarly, management evaluates utility plant for segments attributable to SCE&G
and total assets for SCE&G as a whole, as well as for other operating segments.
Therefore, SCE&G does not allocate accumulated depreciation, common and
non-utility plant, or deferred tax assets to reportable segments. However GENCO
and PSNC do have interest charges, income taxes and deferred tax assets, which
are included in Electric Operations and Gas Distribution, respectively. Interest
income is not reported by segment and is not material. For 2000 adjustments to
net income and income tax expense include the cumulative effect of the
accounting change described in Note 2.
The Consolidated Financial Statements report operating revenues which are
comprised of the energy-related reportable segments. Revenues from
non-reportable segments and investment income from Telecommunications
Investments are included in Other Income. Therefore the adjustments to total
revenue remove revenues from non-reportable segments. Adjustments to Net Income
consist of SCE&G's unallocated net income.
Segment assets include utility plant only (excluding accumulated
depreciation) for SCE&G's Electric Operations, Gas Distribution and Transit
Operations, and all assets for PSNC and the remaining segments. As a result,
adjustments to assets include accumulated depreciation, common and non-utility
plant and non-fixed assets for SCE&G.
Adjustments to Interest Expense, Income Tax Expense (Benefit), Deferred
Tax Assets and Expenditures for Assets include primarily the totals from SCANA
or SCE&G that are not allocated to the segments. Interest Expense is also
adjusted to eliminate inter-affiliate charges. 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. Deferred
Tax Assets are also adjusted to remove the non-current portion of those assets.
Expenditures for Assets are also adjusted for AFC.
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
(Millions of dollars, except per share amounts)
2001 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- --------------------------------------------------- ------------ ------------- -------------- -----------
Total operating revenues $1,318 $740 $710 $683 $3,451
Operating income 173 93 143 119 528
Net income 79 385 63 12 539
Basic and diluted earnings per share .75 3.67 .61 .12 5.15
- ----------------------------------------------------- ------------ ------------- -------------- -----------
2000 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- ----------------------------------------------------- ------------ ------------- -------------- -----------
Total operating revenues $821 $662 $816 $1,134 $3,433
Operating income 172 99 146 137 554
Income before cumulative effect of
Accounting change 75 28 59 59 221
Cumulative effect of accounting change,
net of taxes 29 - - - 29
Net income 104 28 59 59 250
Basic and diluted earnings per share
Before cumulative effect
of accounting change .72 .27 .56 .57 2.12
Cumulative effect of accounting change,
net of taxes .28 - - - .28
Basic and diluted earnings per share 1.00 .27 .56 .57 2.40
16. SUBSEQUENT EVENT
On March 1, 2002, the Company determined that the decline in value of its
investment in DTAG to below its cost basis of $20.30 per share was other than
temporary, and recorded an impairment loss of approximately $160 million (after
tax).
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................. 81
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 92
Item 8. Financial Statements and Supplementary Data.................... 93
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in this
annual report) which are not statements of historical fact are intended to be,
and are hereby identified as, "forward-looking statements" for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. 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) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, (3) changes in the economy,
especially in SCE&G's service territory, (4) the impact of competition from
other energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions,
especially in areas served by SCE&G, (9) inflation, (10) changes in
environmental regulations and (11) the other risks and uncertainties described
from time to time in SCE&G's periodic reports filed with the SEC. SCE&G
disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
After the energy supply and pricing problems experienced in California
in 2000 and 2001, the efforts to restructure electric markets at the state level
have slowed considerably. Many states that had considered legislation to
restructure the electric industry have stopped such efforts or are proceeding
more slowly.
In South Carolina electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2002.
Further, while several companies have announced their intent to site merchant
generating plants in SCE&G's service territory, economic events, environmental
concerns and other factors have slowed those efforts. Legislation or regulatory
action at the Federal level, particularly as part of a larger energy policy
initiative, may be considered in 2002. SCE&G is not able to predict whether any
restructuring legislation or regulatory action will be enacted and, if it is,
the conditions it will impose on utilities.
SCE&G has undertaken a variety of initiatives aimed at preparing for a
restructured electric market. These initiatives include obtaining accelerated
recovery of electric regulatory assets, establishing open access transmission
tariffs and selling bulk power to wholesale customers at market-based rates.
Marketing of services to commercial and industrial customers has increased
significantly, and SCE&G has executed long-term power supply contracts with a
significant portion of its industrial customers. SCE&G believes that these
actions, as well as numerous others that have been and will be taken,
demonstrate its ability and commitment to succeed in the evolving operating
environment.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G's cash requirements arise primarily from its operational needs,
funding its construction program and payment of dividends to SCANA. The ability
of SCE&G to replace existing plant investment, as well as to expand to meet
future demand for electricity and gas, 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. SCE&G's future financial position and
results of operations will be affected by its ability to obtain adequate and
timely rate and other regulatory relief, if requested.
The estimated primary cash requirements for 2002 and the actual primary
cash requirements for 2001, excluding requirements for non-nuclear fuel
purchases, short-term borrowings and dividends, and including notes payable to
affiliated companies, are as follows:
Millions of dollars 2002 2001
- ------------------------------------------------------------- ---------------
Property additions and construction
expenditures, net of AFC $506 $425
Nuclear fuel expenditures 6 4
Investments 11 7
Maturing obligations, redemptions and sinking
and purchase fund requirements 5 5
- ---------------------------------------------------------------- ---------------
Total $528 $441
================================================================ ===============
Approximately 68 percent of total cash requirements was provided from
internal sources in 2001 as compared to 63 percent in 2000.
For the years 2003-2006, SCE&G has an aggregate of $578.4 million of
long-term debt and preferred stock maturing, which includes an aggregate of
$576.2 million for debt and $2.2 million of purchase or sinking fund
requirements for SCE&G's preferred stock. SCE&G's long-term debt maturities for
the years 2003-2006 include approximately $93.8 million for sinking fund
requirements all of which may be satisfied by deposit and cancellation of bonds
issued upon the basis of property additions or bond retirement credits. These
obligations and other commitments are tabulated below.
Contractual Cash Obligations
Less than After
December 31, 2001 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of dollars)
Long-term and short-term debt
(including interest) $2,887 $275 $634 $275 $1,703
Preferred stock sinking funds 11 1 2 1 7
Operating leases 78 12 31 18 17
Other commercial commitments 381 167 203 1 10
Included in other commercial commitments are estimated obligations for
coal supply purchases. Actual purchases are included in fuel used in electric
generation and recovered through electric rates.
SCE&G anticipates that its contractual cash obligations will be met
through internally generated funds and the incurrence of additional short-term
and long-term indebtedness. SCE&G expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements for the foreseeable
future.
Financing Limits and Related Matters
SCE&G's issuance of various securities including long-term and short-term
debt is subject to customary approval or authorization by state and Federal
regulatory bodies including SCPSC, the SEC and FERC. The following paragraphs
describe the financing programs currently utilized by SCE&G.
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945
(Old Mortgage), contains provisions prohibiting the issuance of additional bonds
thereunder (Class A Bonds) unless net earnings (as therein defined) for 12
consecutive months out of the 18 months prior to the month of issuance are at
least twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 2001 the Bond Ratio
was 5.77. The Old Mortgage allows the issuance of additional Class A Bonds up to
an additional principal amount equal to (i) 70 percent of unfunded net property
additions (which unfunded net property additions totaled approximately $1,759
million at December 31, 2001), (ii) retirements of Class A Bonds (which
retirement credits totaled $44.9 million at December 31, 2001), and (iii) cash
on deposit with the Trustee.
SCE&G is also subject to a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties under which its
future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued
under the New Mortgage on the basis of a like principal amount of Class A Bonds
issued under the Old Mortgage which have been deposited with the Trustee of the
New Mortgage. New Bonds will be issuable under the New 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 (including Class A Bonds) and New
Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 2001
the New Bond Ratio was 5.71.
SCE&G's Restated Articles of Incorporation prohibit issuance of
additional shares of preferred stock without the consent of the preferred
shareholders unless net earnings (as defined therein) 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, 2001 the
Preferred Stock Ratio was 1.83.
Without the consent of at least a majority of the total voting power of
SCE&G's preferred stock, SCE&G may not 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;
however, 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, 2001 SCE&G had $250 million of unused authorized lines of
credit under a credit agreement supporting the issuance of commercial paper.
SCE&G's commercial paper outstanding at December 31, 2001 and 2000 was $114.7
million and $117.5 million, respectively. In addition, Fuel Company has a credit
agreement for a maximum of $125 million with the full amount available at
December 31, 2001. The credit agreement supports the issuance of short-term
commercial paper for the financing of nuclear and fossil fuels and sulfur
dioxide emission allowances. Fuel Company commercial paper outstanding at
December 31, 2001 and 2000 was $50.1 million and $70.2 million, respectively.
This commercial paper and amounts outstanding under the revolving credit
agreement, if any, are guaranteed by SCE&G.
Financing Transactions and Other Information
The following financing transactions have occurred since January 1, 2001:
o On January 24, 2001 SCE&G issued $150 million of first mortgage bonds
having an annual interest rate of 6.70 percent and maturing on February 1,
2011. The proceeds from the sale of these bonds were used to reduce
short-term debt and for general corporate purposes.
o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625 percent and maturing February 1,
2032. The proceeds from the sale of these bonds were used to reduce
short-term debt primarily incurred as a result of SCE&G's construction
program and to redeem its First and Refunding Mortgage Bonds, 8 7/8 percent
Series due August 15, 2021.
SCE&G is constructing a $256 million gas turbine generator project in
Aiken County, South Carolina. Two combined-cycle turbines will burn natural gas
to produce 300 megawatts of new electric generation and use exhaust heat to
replace coal-fired steam that powers two existing 75 megawatt turbines at the
Urquhart Generating Station. The turbine project is scheduled to be completed by
June 2002.
In October 1999 FERC notified SCE&G of its agreement with SCE&G's plan
to reinforce Lake Murray Dam in order to maintain the lake in case of an extreme
earthquake. Construction for the project and related activities, which began in
the third quarter of 2001, is expected to cost $250 million and be completed in
2005. Any costs incurred by SCE&G are expected to be recoverable through
electric rates.
In October 2001 SCE&G filed with the SCPSC its siting plans to construct
an 875 megawatt generation facility in Jasper County, South Carolina, to supply
electricity to its South Carolina customers. The facility will include three
natural gas combustion-turbine generators and one steam-turbine generator.
Construction of the $450 million facility is expected to begin in April 2002,
with commercial operation in the summer of 2004. In connection with the
facility, SCE&G has signed a 250 megawatt electric supply contract with North
Carolina Electric Membership Corporation for a term of at least nine years
beginning January 1, 2004.
ENVIRONMENTAL MATTERS
Electric Operations
The Clean Air Act Amendment of 1990 (CAA) required electric utilities
to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by
the year 2000. SCE&G's compliance with these reductions has been accomplished.
The EPA has indicated that it will propose regulations by December 2003 for
stricter limits on mercury and other toxic pollutants generated by coal-fired
plants.
SCE&G currently estimates that air emissions control equipment will
require capital expenditures of $72 million over the 2002-2006 period to
retrofit existing facilities, with increased operation and maintenance costs of
approximately $1.2 million per year. To meet compliance requirements for the
years 2007 through 2011, SCE&G anticipates additional capital expenditures of
approximately $6 million.
In October 1998 the EPA issued a final rule requiring 22 states,
including South Carolina, to modify their state implementation plans (SIP) to
address the issue of NOx pollution. While not final, South Carolina has proposed
NOx reductions that would require SCE&G to install pollution control equipment
to reduce its NOx emissions. Capital expenditures will be required to comply
with the NOx reductions and they are included in the cost figures above.
The EPA has undertaken an aggressive enforcement initiative against the
industry and the Department of Justice has brought suit against a number of
utilities in Federal court alleging violations of the CAA. 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 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 has received and responded to Section 114 requests for information related
to Canadys and Wateree Stations. The regulations under the CAA provide certain
exemptions to the definition of "major modifications," including an exemption
for routine repair, replacement or maintenance. SCE&G has analyzed each of the
activities covered by the EPA's requests and believes that each of these
activities is covered by the exemption for routine repair, replacement and
maintenance. The regulations also provide an exemption for an increase in
emissions resulting from increased hours of operation or production rate and
from demand growth. It is possible that the EPA will commence enforcement
actions against SCE&G, 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 two plants. SCE&G believes that any
assertions relative to SCE&G's compliance with the CAA would be without merit.
However, if successful, such assertions could have a material adverse effect on
SCE&G's financial position, cash flows and results of operations.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require treatment for wastewater discharges. Under
this 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 generating units. Concurrent with renewal of these
permits, the permitting agency has implemented a more rigorous program in
monitoring and controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. SCE&G has been developing compliance plans for
these initiatives. Amendments to the Clean Water Act proposed in Congress
include several provisions which, if passed, could prove costly to SCE&G. These
include, but are not limited to, limitations to mixing zones and the
implementation of technology-based standards.
Gas Distribution
SCE&G 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 to regulated operations and are deferred and amortized with
recovery provided through rates. Deferred amounts, net of amounts previously
recovered through rates and insurance settlements, totaled $24.4 million and
$20.2 million at December 31, 2001 and 2000, respectively. The deferral includes
the estimated costs associated with the following matters.
o In September 1992 the EPA notified SCE&G, among others, of its
potential liability for the investigation and cleanup of the Calhoun
Park area site in Charleston, South Carolina. This site encompasses
approximately 30 acres and includes properties which were locations
for various industrial operations, including one of SCE&G's
decommissioned MGPs. Field work at the site began in November 1993 and
has required the submission of several investigative reports and the
implementation of several work plans. In September 2000, SCE&G was
notified by the South Carolina Department of Health and Environmental
Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park
area site. The EPA required that SCE&G conduct a focused Remedial
Investigation/Feasibility Study on the intermediate aquifer, which was
completed in June 2001. The EPA expects to issue a Record of Decision
dealing with the intermediate aquifer and sediments in June 2002.
SCE&G anticipates that major remediation activities will be completed
in 2003, with certain monitoring activities continuing until 2007. As
of December 31, 2001, SCE&G has spent approximately $15.8 million to
remediate the Calhoun Park area site. Total remediation costs are
estimated to be $21.9 million.
o SCE&G owns three other decommissioned MGP sites in South Carolina
which contain residues of by-product chemicals. Two of these sites are
currently being remediated under work plans approved by DHEC. SCE&G is
continuing to investigate the remaining site and is monitoring the
nature and extent of residual contamination. SCE&G anticipates that
major remediation activities for these three sites will be completed
between 2003-2005. SCE&G has spent approximately $2.0 million related
to these sites, and expects to incur an additional $6.0 million.
REGULATORY MATTERS - STATE
Regulated public utilities are allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory environment occur, SCE&G may no longer be eligible to apply this
accounting treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of deregulation cannot be
determined at present, discontinuation of the accounting treatment could have a
material adverse effect on SCE&G's results of operations in the period the
write-off would be recorded. It is expected that cash flows and the financial
position of SCE&G would not be materially affected by the discontinuation of the
accounting treatment. SCE&G reported approximately $217 million and $81 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities of approximately $125 million and
$71 million, respectively, on its balance sheet at December 31, 2001.
SCE&G'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,
SCE&G could be required to write down its investment in these assets. SCE&G
cannot predict whether any write-downs will be necessary and, if they are, the
extent to which they would adversely affect SCE&G's results of operations in the
period in which they would be recorded. As of December 31, 2001, SCE&G's net
investment in fossil/hydro and nuclear generation assets was $1,385.5 million
and $572.9 million, respectively.
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric,
gas and transit rates, service, accounting, issuance of securities (other than
short-term promissory notes) and other matters.
Electric
On April 24, 2001 the SCPSC approved SCE&G's request to increase the
fuel component of rates charged to electric customers from 1.330 cents per
kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2001 through April 2002. The increase
also provides recovery over a two-year period of under-collected actual fuel
costs through April 2001, including short-term purchased power costs
necessitated by outages at two of SCE&G's base load generating plants in winter
2000-2001. The new rates were effective as of the first billing cycle in May
2001.
On September 14, 1999 the SCPSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating Station. The plan was implemented beginning
January 1, 2000 for a three-year period. The SCPSC approved an accelerated
capital recovery methodology wherein SCE&G may increase depreciation of its Cope
Generating Station in excess of amounts that would be recorded based upon
currently approved depreciation rates. The amount of the accelerated
depreciation will be determined by SCE&G based on the level of revenues and
operating expenses, not to exceed $36 million annually without the approval of
the SCPSC. Any unused portion of the $36 million in any given year may be
carried forward for possible use in the following year. As of December 31, 2001
no accelerated depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
On January 9, 1996 the SCPSC authorized a return on common equity of 12.0
percent. The SCPSC also approved establishment of a Storm Damage Reserve Account
capped at $50 million to be collected through rates over a ten-year period.
Additionally, the SCPSC approved accelerated amortization of a significant
portion of SCE&G's electric regulatory assets (excluding deferred income tax
assets) and the remaining transition obligation for postretirement benefits
other than pensions, which enabled SCE&G to recover the balances as of the end
of the year 2000.
Gas
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 component in effect during the years ended December
31, 2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.993 January-February 2001 $.543 January-July 2000
$.793 March-October 2001 $.688 August-October 2000
$.596 November-December 2001 $.782 November-December 2000
On July 5, 2000 the SCPSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million. The retroactive effect was
recorded in the second quarter of 2000.
In 1994 the SCPSC issued an order approving SCE&G's request to recover
through a billing surcharge to its gas customers the costs of environmental
cleanup at the sites of former MGPs. The billing surcharge is subject to annual
review and provides for the recovery of substantially all actual and projected
site assessment and cleanup costs and environmental claims settlements for
SCE&G's gas operations that had previously been deferred. In October 2001, as a
result of the annual review, the SCPSC approved SCE&G's request to increase the
billing surcharge from 1.1cents per therm to 3.0 cents per therm, which is
intended to provide for the recovery, prior to the end of the year 2005, of the
balance remaining at December 31, 2001 of $24.4 million.
Transit
In September 1992 the SCPSC issued an order granting SCE&G's request for
a $.25 increase in transit fares from $.50 to $.75 in Columbia, South Carolina;
however, the SCPSC also required $.40 fares for low income customers and denied
SCE&G's request for certain bus route and schedule changes. The new rates were
placed into effect in October 1992. After several appeals and petitions for
reconsideration to the Circuit Court and the Supreme Court by the various
parties, on September 27, 2000 the SCPSC issued an order granting certain relief
requested by SCE&G. On September 29, 2000 the Consumer Advocate filed a motion
with the SCPSC for a stay of this order. On October 3, 2000 the SCPSC accepted
the Consumer Advocate's motion and issued a stay of its order. The Consumer
Advocate and other intervenors have petitioned the Circuit Court for judicial
review of the SCPSC's order granting relief. The Circuit Court has held in
abeyance any appellate review pending the outcome of current negotiations on the
transfer of the transit system from SCE&G to an unaffiliated regional transit
authority.
REGULATORY MATTERS - FEDERAL
SCE&G's regulated business operations were impacted by FERC Orders No.
636, 888 and 2000. Order No. 636 was intended to deregulate the markets for
interstate sales of natural gas by requiring that pipelines provide
transportation services that are equal in quality for all gas suppliers whether
the customer purchases gas from the pipeline or another supplier. Orders No. 888
and 2000 require utilities under FERC jurisdiction that own, control or operate
transmission lines to file nondiscriminatory open access tariffs that offer to
others the same transmission service they provide to themselves and to submit
plans for the possible formulation of an RTO. In the opinion of SCE&G, it
continues to be able to meet successfully the challenges of these altered
business climates and does not anticipate any material adverse impact on the
results of operations, cash flows, financial position or business prospects.
As already noted, Order No. 2000 required utilities which operate
electric transmission systems to submit plans for the possible formation of
RTOs. In March 2001 FERC gave provisional approval to SCE&G and two other
southeastern electric utilities to establish GridSouth Transco, LLC (GridSouth)
as an independent regional transmission company, responsible for operating and
planning the utilities' combined transmission systems. In July 2001 FERC
expressed its desire that utilities throughout the United States combine their
transmission systems to create four large independent regional operators, one
each in the Northeast, Southeast, Midwest and West. Accordingly, FERC ordered
mediation talks to take place between the utilities forming GridSouth and
certain groups that had proposed other RTOs. These talks were mediated by an
administrative law judge, who issued her nonbinding mediation report to FERC in
September 2001. The report made recommendations related to the formation of a
Southeast regional RTO. While FERC has not acted on the mediation report, and
the timing or impact of future FERC orders related to RTOs cannot be predicted,
SCE&G expects to be reimbursed or to otherwise recover costs it has incurred in
connection with RTO formation.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of SCE&G's accounting policies which are new
or most critical in terms of reporting results of operations.
SFAS 71 - SCE&G is subject to the provisions of SFAS 71, 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.
Aside from other impacts which might be experienced as a result of deregulation
or other significant changes in the regulatory environments of the utilities,
SFAS 71 could cease to be applicable and SCE&G could be required to write off
such regulatory assets and liabilities (see also COMPETITION).
Provisions for bad debts / Allowances for doubtful accounts - As of each
balance sheet date, SCE&G evaluates the collectibility of accounts receivable
and records allowances for doubtful accounts based on estimates of the level of
actual write-offs which might be experienced. These estimates are based on,
among other things, comparisons of the relative age of accounts and
consideration of actual write-off history.
Pension accounting - SCE&G follows SFAS 87 in accounting for its defined
benefit pension plan. SCE&G's plan is well funded and as such, significant net
pension income is reflected in the financial statements (see Result's 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 returns on
assets. Net pension income of $41.1 million recorded in 2001 reflects the use of
an 8 percent discount rate and an assumed 9.5 percent long-term return on plan
assets. SCE&G believes that these assumptions are, and that the resulting
pension income amount is, reasonable. Were SCE&G to have alternatively selected
a discount rate of 7.5 percent and a rate of return on assets of 9 percent, the
net pension income recorded in 2001 would have been reduced by approximately
$5.9 million.
Accounting for postretirement benefits other than pensions - Similar to
its pension accounting, SCE&G follows SFAS 106 in accounting for its
postretirement medical and life insurance benefits. This plan is unfunded, so no
return on assets impacts the net expense recorded; however, the selection of
discount rates can significantly impact the actuarial determination of net
expense. SCE&G used a discount rate of 8 percent and recorded a net SFAS 106
cost of $14.4 million for 2001. Were the selected discount rate to have been 7.5
percent, the expense would have been approximately $0.4 million higher.
SFAS 143, "Accounting for Asset Retirement Obligations, provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). SCE&G will adopt SFAS
143 effective January 1, 2003. The impact SFAS 143 may have on SCE&G's results
of operations, cash flows or financial position has not been determined but
could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," are effective January 1, 2002. This Statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on SCE&G's financial statements from the initial adoption of
SFAS 144.
AFFILIATE TRANSACTIONS
SCE&G has two equity-method investments in partnerships involved in
converting coal to alternate fuel, the use of which fuel qualifies for favorable
Federal income tax treatment (tax credits). The aggregate investment in these
partnerships as of December 31, 2001 is approximately $3 million, and through
December 31, 2001, they had generated and passed through to SCE&G approximately
$28 million in such tax credits. Under a plan approved by the SCPSC, any tax
credits generated and ultimately passed through to SCE&G have been and will be
deferred and used to offset defined capital expenditures such as those related
to reduction of environmental emissions.
OTHER MATTERS
Claims and Litigation
SCANA and Westvaco each own a 50 percent interest in Cogen South LLC
(Cogen). Cogen built and operates a cogeneration facility in North Charleston,
South Carolina. On September 10, 1998 the contractor in charge of construction
filed suit in Circuit Court alleging that it incurred construction cost overruns
relating to the facility and that the construction contract provides for
recovery of these costs. In addition to Cogen, Westvaco, SCE&G and SCANA were
named as defendants in the suit. Cogen filed a separate suit against the
contractor for delay and performance issues. The suits were combined and the
contractor brought the manufacturer of the generator into the performance suit.
In November 2001 a settlement was reached between all parties. Terms of the
settlement are confidential, but the settlement's impact on SCE&G's results of
operations, cash flow and financial position is not material.
SCE&G is also engaged in various other claims and litigation incidental
to its business operations which management anticipates will be resolved without
material loss to SCE&G.
RESULTS OF OPERATIONS
Net Income
Net income and the percent change from the previous year for the years
2001, 2000 and 1999 were as follows:
Millions of dollars 2001 2000 1999
- ------------------------------------------------------------------------------
Net income derived from:
Continuing operations $221.9 $231.3 $189.2
Cumulative effect of accounting
change, net of taxes - 22.3 -
- ------------------------------------------------------------------------------
Net income $221.9 $253.6 $189.2
==============================================================================
Percent increase (decrease) in net income (12.50%) 34.04% (16.75%)
==============================================================================
o 2001 vs 2000 Net income decreased primarily as a result of milder
weather and a slowing economy.
o 2000 vs 1999 Net income increased primarily as a result of more
favorable weather, customer growth and pension income. These were
partially offset by higher purchased power costs and a charge for
repairs at Summer Station.
Pension income recorded by SCE&G reduced operations expense by $20.6
million, $20.9 million and $16.3 million for the years ended December 31, 2001,
2000 and 1999, respectively. In addition, pension income increased other income
by $12.7 million, $12.9 million and $10.5 million for the years ended December
31, 2001, 2000 and 1999, respectively. Effective July 1, 2000 SCE&G's pension
plan was amended to provide a cash balance formula. The effect of this plan
amendment was to reduce net periodic benefit income for the year ended December
31, 2000 by approximately $3.4 million.
SCE&G's financial statements include the recording of an 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. An equity portion of AFC is
included in nonoperating income and a debt portion of AFC is included in
interest charges (credits) as noncash items, both of which have the effect of
increasing reported net income. AFC represented approximately 6.5 percent of
income before income taxes in 2001, 1.7 percent in 2000 and 2.0 percent in 1999.
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
Fuel Company. Electric operations sales margins, for 2001, 2000 and 1999,
excluding the cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2001 2000 1999
- ----------------------------------------------- -------------- ------------
Operating revenues $1,374.0 $1,343.8 $1,226.0
Less: Fuel used in generation (223.9) (231.6) (214.4)
Purchased power (233.9) (182.7)
(141.5)
- ----------------------------------------------- -------------- ------------
Margin $916.2 $929.5 $870.1
=============================================== ============== ============
o 2001 vs 2000 Sales margin decreased primarily due to milder weather
and the impact of the slowing economy, which was partially offset by
customer growth and lower fuel costs.
o 2000 vs 1999 Sales margin increased primarily due to more favorable
weather and customer growth.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes, excluding volumes attributable to the cumulative effect of
accounting change in 2000, were as follows:
Classification 2001 % Change 2000 % Change
--------------------------------------------------------------------- --------
Residential (170,509) (2.5%) 396,179 6.3%
Commercial (17,194) - 353,621 5.9%
Industrial (317,659) (4.7%) 524,969 8.5%
Sales for resale
(excluding interchange) (108,236) (8.8%) 33,505 2.8%
Other (18,927) (3.4%) 34,676 6.7%
--------------------------------------------- ------------
Total territorial (632,525) (3.0%) 1,342,950 6.7%
Negotiated Market Sales Tariff 207,984 10.0% 264,257 15.7%
--------------------------------------------- ------------
Total (424,541) (2.0%) 1,607,207 7.4%
===================================================================== ========
o 2001 vs 2000 Sales volume decreased primarily due to milder weather
and the impact of the slowing economy.
o 2000 vs 1999 Sales volume increased primarily due to more favorable
weather and customer growth.
In March 2001 Summer Station returned to service after having been taken
out of service on October 7, 2000 for a planned maintenance and refueling
outage. During initial inspection activities, plant personnel discovered a small
leak in a weld in a primary coolant system pipe. Repairs were completed and the
integrity of the new welds was verified through extensive testing. The NRC was
closely involved throughout this process and approved SCE&G's actions, as well
as the restart schedule.
Also in April 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
returned to service after having been taken out of service in January 2001 due
to an electrical ground in the generator. The SCPSC has approved recovery of the
cost of replacement power related to both of these outages through SCE&G's fuel
adjustment clause.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Gas distribution sales margins for 2001, 2000 and 1999, excluding the
cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2001 2000 1999
-----------------------------------------------------------------------
Operating revenues $341.0 $325.1 $239.0
Less: Gas purchased for resale (251.6) (233.8) (152.6)
-----------------------------------------------------------------------
Margin $89.4 $91.3 $86.4
=======================================================================
o 2001 vs 2000 Sales margin decreased primarily as a result of the
slowing economy and increased competition with alternate fuels.
o 2000 vs 1999 Sales margin increased primarily as a result of more
favorable weather.
Increases (decreases) from the prior year in dekatherm (DT) sales volume by
classes, including transportation gas and excluding volumes attributable to the
cumulative effect of accounting change in 2000, were as follows:
Classification 2001 % Change 2000 % Change
- ---------------------------------- ------------- -------------- -------------
Residential (3,249,400) (22.4%) 2,682,707 22.7%
Commercial (1,511,368) (11.8%) 1,118,193 9.6%
Industrial (2,828,121) (16.5%) (828,737) (4.6)%
Transportation gas 375,436 18.0% 110,220 5.6%
--- ------- ---- -------
- -------------------
Total (7,213,453) (15.5%) 3,082,383 7.1%
================================== ============= ============== =============
o 2001 vs 2000 Sales volume decreased due to the slowing economy and use
of alternate fuels by industrial customers.
o 2000 vs 1999 Sales volume increased due to colder weather and customer
growth, which were partially offset by curtailments and use of
alternate fuels by industrial customers. Other Operating Expenses
Increases (decreases) in other operating expenses were as follows:
Millions of dollars 2001 % Change 2000 % Change
- -------------------------------------------------------------------------------
Other operation and maintenance $7.0 2.3% $(7.3) (2.3%)
Depreciation and amortization 5.1 3.2% 4.8 3.1%
Other taxes 1.5 1.5% 3.5 3.7%
- ----------------------------------------- -------------
Total $13.6 2.4% $1.0 0.2%
===============================================================================
o 2001 vs 2000 Other operation and maintenance expenses increased
primarily as a result of increases in employee benefit costs.
Depreciation and amortization increased primarily as a result of
normal increases in utility plant. Other taxes increased primarily due
to increased property taxes.
o 2000 vs 1999 Other operation and maintenance decreased due to pension
income (see Net Income), which was partially offset by increased
maintenance costs for electric generating and distribution facilities.
Depreciation and amortization increased primarily due to normal
increases in utility plant. Other taxes increased primarily due to
increased property taxes.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
Millions of dollars 2001 % Change 2000 % Change
- --------------------------------------------------------------------------------
Interest on long-term debt, net $12.0 11.9% $4.0 4.1%
Other interest expense (2.4) (29.6%) (0.5) (5.8%)
- --------------------------------------------- -----------
Total $9.6 8.8% $3.5 3.3%
================================================================================
Interest expense in 2001 increased as a result of increased borrowings.
Interest expense in 2000 increased as a result of increased borrowings and
increased weighted average interest rates on short-term and long-term
borrowings.
Income Taxes
Income taxes decreased approximately $9.8 million for the year 2001
compared to 2000 and increased approximately $23.4 million for the year ended
2000 compared to 1999. Changes in income taxes are primarily due to changes in
operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
December 31, 2001 Expected Maturity Date
Millions of dollars
Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value
- ---------------------------- ------------ ----------- ----------- ----------- ------------ ------------- ------------ ------------
Long-Term Debt:
Fixed Rate ($) 27.6 129.7 123.9 173.9 154.7 1,561.0 1,542.9
951.2
Average Interest Rate 6.73% 6.37% 7.52% 7.40% 8.66% 7.33% 7.33%
December 31, 2000 Expected Maturity Date
Millions of dollars
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value
- ---------------------------- ------------ ----------- ----------- ----------- ------------ ------------- ------------ ------------
Long-Term Debt:
Fixed Rate ($) 27.6 27.6 129.5 123.9 173.9 932.5 1,415.0 1,331.6
Average Interest Rate 6.72% 6.72% 6.37% 7.52% 7.40% 7.55% 7.39%
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report............................................... 94
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2001 and 2000................ 95
Consolidated Statements of Income for years ended December 31, 2001,
2000 and 1999............................................................ 97
Consolidated Statements of Cash Flows for the years ended December 31,
2001, 2000 and 1999..................................................... 98
Consolidated Statements of Capitalization as of December 31, 2001
and 2000.................................................................99
Consolidated Statements of Common Equity for the years ended December 31,
2001, 2000 and 1999.................................................... 101
Notes to Consolidated Financial Statements................................ 102
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of South Carolina Electric & Gas Company (Company) as of December
31, 2001 and 2000 and the related Consolidated Statements of Income, Common
Equity and of Cash Flows for each of the three years in the period ended
December 31, 2001. Our audits also included the financial statement schedule
listed in Part IV at Item 14. 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 auditing standards generally accepted
in the United States of America. 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 the Company at December 31, 2001
and 2000 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2001 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 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for operating
revenues.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 8, 2002
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------- ---------------- -------------------
December 31, (Millions of dollars) 2001 2000
- ------------------------------------------------------------------------------------- ---------------- -------------------
Assets
Utility Plant (Notes 1 & 5):
Electric $4,563 $4,453
Gas 425 409
Other 188 186
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total 5,176 5,048
Less accumulated depreciation and amortization 1,841 1,720
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total 3,335 3,328
Construction work in progress 511 230
Nuclear fuel, net of accumulated amortization 45 57
- ------------------------------------------------------------------------------------- ---------------- -------------------
Utility Plant, Net 3,891 3,615
- ------------------------------------------------------------------------------------- ---------------- -------------------
Nonutility Property and Investments, Net 24 21
- ------------------------------------------------------------------------------------- ---------------- -------------------
Current Assets:
Cash and temporary investments (Notes 1 &11) 78 60
Receivables 212 284
Receivables - affiliated companies 4 3
Inventories (At average cost) (Note 6):
Fuel 39 21
Materials and supplies 48 46
Emission allowances 13 20
Prepayments 6 5
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total Current Assets 400 439
- ------------------------------------------------------------------------------------- ---------------- -------------------
Deferred Debits:
Environmental 24 20
Nuclear plant decommissioning fund (Note 1) 79 72
Pension asset, net (Note 4) 239 196
Due from affiliates - postretirement benefits (Note 4) 15 13
Other regulatory assets (Note 1) 193 191
Other 97 104
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total Deferred Debits 647 596
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total $4,962 $4,671
===================================================================================== ================ ===================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------- -------------------- --------------------
December 31, (Millions of dollars) 2001 2000
------------------------------------------------------------------------- -------------------- --------------------
Capitalization and Liabilities
Shareholders' Investment:
Common equity (Note 8) $1,750 $1,657
Preferred stock (Not subject to purchase or sinking funds) (Note 9) 106 106
------------------------------------------------------------------------- -------------------- --------------------
Total Shareholders' Investment 1,856 1,763
Preferred Stock, net (Subject to purchase or sinking funds) (Note 9) 10 10
Company-Obligated Mandatorily Redeemable Preferred Securities of the
Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million
principal amount of the 7.55%
Junior Subordinated Debentures of SCE&G, due 2027 (Note 9) 50 50
Long-Term Debt, net (Notes 5 & 11) 1,412 1,267
------------------------------------------------------------------------- -------------------- --------------------
Total Capitalization 3,328 3,090
------------------------------------------------------------------------- -------------------- --------------------
Current Liabilities:
Short-term borrowings (Notes 6, 7 & 11) 165 188
Current portion of long-term debt (Note 5) 28 28
Accounts payable 99 103
Accounts payable - affiliated companies (Note 1) 78 58
Customer prepayment and deposits 19 17
Taxes accrued 80 51
Interest accrued 27 22
Dividends declared 42 44
Deferred income taxes, net (Notes 1 & 10) 12 20
Other 8 10
------------------------------------------------------------------------- -------------------- --------------------
Total Current Liabilities 558 541
------------------------------------------------------------------------- -------------------- --------------------
Deferred Credits:
Deferred income taxes, net (Notes 1 & 10) 599 584
Deferred investment tax credits (Notes 1 & 10) 109 109
Reserve for nuclear plant decommissioning (Note 1) 79 72
Due to affiliates - pension asset (Note 4) 16 14
Postretirement benefits (Note 4) 122 113
Regulatory liabilities 81 65
Other 70 83
------------------------------------------------------------------------- -------------------- --------------------
Total Deferred Credits 1,076 1,040
------------------------------------------------------------------------- -------------------- --------------------
Commitments and Contingencies (Note 12) - -
------------------------------------------------------------------------- -------------------- --------------------
Total $4,962 $4,671
========================================================================= ==================== ====================
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
For the Years Ended December 31, 2001 2000 1999
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
(Millions of Dollars, except per share amounts)
Operating Revenues (Notes 1, 2 & 3):
Electric $1,374 $1,344 $1,226
Gas 341 325 239
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Operating Revenues 1,715 1,669 1,465
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Operating Expenses:
Fuel used in electric generation 224 232 214
Purchased power (including affiliated purchases) 234 183 142
Gas purchased for resale 252 234 153
Other operation and maintenance 315 308 316
Depreciation and amortization (Note 1) 163 158 153
Other taxes 99 97 94
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Operating Expenses 1,287 1,212 1,072
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Operating Income 428 457 393
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Other Income:
Other Income, including allowance for equity funds used
during construction (Note 1) 26 14 9
Gain on sale of assets 4 2 3
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Other Income 30 16 12
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Interest Charges, Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 458 473 405
Interest Charges, Net of Allowance for Borrowed Funds Used
During Construction (Note 1) 109 105 102
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 349 368 303
Income Taxes (Note 10) 123 133 110
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 226 235 193
Preferred Dividend Requirement of Company - Obligated
Mandatorily Redeemable Preferred Securities 4 4 4
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Cumulative Effect of Accounting Change 222 231 189
Cumulative Effect of Accounting Change, net of taxes (Note 2) - 22 -
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Net Income 222 253 189
Preferred Stock Cash Dividends (At stated rates) 7 7 7
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Earnings Available for Common Shareholder $215 $246 $182
========================================================================== =================== =============== ================ =
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) 2001 2000 1999
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Operating Activities:
Net income $222 $253 $189
Adjustments to reconcile net income to net cash provided from
operating activities:
Cumulative effect of accounting change, net of taxes - (22) -
Depreciation and amortization 165 159 154
Amortization of nuclear fuel 16 16 18
Gain on sale of assets (4) (2) (3)
Allowance for funds used during construction (22) (6) (6)
Under collection, fuel adjustment clause (3) (34) (6)
Changes in certain assets and liabilities:
(Increase) decrease in receivables 71 (56) (17)
(Increase) decrease inventories (13) 8 (16)
(Increase) decrease in pension asset (43) (43) (29)
(Increase) decrease in other regulatory assets 1 15 16
Increase (decrease) in deferred income taxes, net 27 60 16
Increase (decrease) in other regulatory liabilities 22 6 (6)
Increase (decrease) in postretirement benefits 9 15 11
Increase (decrease) in accounts payable 16 50 (9)
Increase (decrease) in taxes accrued 29 (23) (15)
Other, net (32) (17) 13
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From Operating Activities 461 379 310
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (427) (277) (227)
Increase in nonutility property (2) (1) -
Proceeds on sales of assets 3 2 3
Increase in investments (7) (1) (6)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Investing Activities (433) (277) (230)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 149 148 99
Capital contribution from parent 33 - -
Repayment and repurchases:
Mortgage bonds - (100) (10)
Notes and loans - - -
Other long-term debt (5) (4) (9)
Preferred stock - (1) -
Dividend payments:
Common Stock (157) (131) (133)
Preferred stock (7) (7) (7)
Short-term borrowings, net (23) (25) 22
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Financing Activities (10) (120) (38)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Temporary Investments 18 (18) 42
Cash and Temporary Investments, January 1 60 78 36
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash and Temporary Investments, December 31 $78 $60 $78
======================================================================= ============ ============= =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $9, $4 $131 $102 $99
and $3)
- Income taxes 70 97 94
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
December 31, (Millions of dollars) 2001 2000
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Common Equity (Note 8):
Common stock, $4.50 par value, authorized 50,000,000 shares;
issued and outstanding 40,296,147 shares in 2001 and 2000 $181 $181
Premium on common stock 395 395
Other paid-in capital 470 437
Capital stock expense (5) (5)
Retained earnings 709 649
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Total Common Equity 1,750 53 % 1,657 54%
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Cumulative Preferred Stock (Not subject to purchase or sinking funds) $100 Par
Value - Authorized 1,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Redemption Price
Outstanding
Series 2001 2000
------ ---- ----
$100 Par 6.52% 1,000,000 1,000,000 100.00 100 100
$50 Par 5.00% 125,209 125,209 52.50 6 6
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Total Preferred Stock (Not subject to purchase or sinking funds) (Note 9) 106 3 % 106 3%
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Cumulative Preferred Stock (Subject to purchase and sinking funds)
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 2000
and 1999 $50 Par Value - Authorized 1,560,287 shares
Shares Outstanding
Series 2001 2000 Redemption Price
------ ---- ---- ----------------
4.50% 8,397 9,600 51.00 1 1
4.60% (A) 14,052 16,052 51.00 1 1
4.60% (B) 54,400 57,800 50.50 3 3
5.125% 66,000 67,000 51.00 3 3
6.00% 66,635 69,835 50.50 3 3
------------- -----------
Total 209,484 220,287
============= ===========
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999
- ----------------------------------------------------------------------------------------- ------------ -------- ----------- --------
Total Preferred Stock (Subject to purchase or sinking funds) 11 11
Less: Current portion, including sinking funds requirements (1) (1)
- ----------------------------------------------------------------------------------------- ------------ -------- ----------- --------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11) 10 - % 10 -%
- ----------------------------------------------------------------------------------------- ------------ -------- ----------- --------
Company-Obligated Mandatorily Redeemable Preferred Securities of Company's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55% Junior Subordinated Debentures of the Company, due 2027 (Note 9) 50 2% 50 2%
- ----------------------------------------------------------------------------------------- ------------ -------- ----------- --------
------------------------------------------------------------- ----------- -------------- -------- -------------- -----------
December 31, (Millions of dollars) 2001 2000
------------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Long-Term Debt (Notes 5 & 11)
First Mortgage Bonds:
Series Year of Maturity
6 1/4% 2003 $100 $100
7.70% 2004 100 100
7 1/2% 2005 150 150
6 1/8% 2009 100 100
6.70% 2011 150 -
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage Bonds:
Series Year of Maturity
9% 2006 131 131
8 7/8% 2021 103 103
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984, due 2014 (6.50%) 57 57
Orangeburg County Series 1994, due 2024 (5.70%) 30 30
Other 16 17
Charleston Franchise Agreement, due 1997-2002 4 7
Other 2 3
------------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Long-Term Debt 1,443 1,298
Less - Current maturities, including sinking fund (28) (28)
requirements
- Unamortized discount (3) (3)
------------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Long-Term Debt, Net 1,412 42% 1,267 41%
------------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Capitalization $3,328 100% $3,090 100%
============================================================= =========== ============== ======== ============== ===========
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Premium Other Capital Total
Millions of dollars Common Stock On Common Paid in Stock Retained Common
Shares Amount Stock Capital Expense Earnings Equity
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Balance at December 31, 1998 40,296,147 $181 $395 $437 $(5) $491 $1,499
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Net Income 182 182
Cash Dividends Declared (123) (123)
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Balance at December 31, 1999 40,296,147 181 395 437 (5) 550 1,558
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Net Income 246 246
Cash Dividends Declared (147) (147)
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Balance at December 31, 2000 40,296,147 181 395 437 (5) 649 1,657
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
Capital Contributions From Parent 33 - 33
Net Income 215 215
Cash Dividends Declared (155) (155)
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- ----------- -----------
- ------------------------------------------ ------------ ---------- --------------- ------------ ---------- -----------
Balance at December 31, 2001 40,296,147 $181 $395 $470 $(5) $709 $1,750
========================================== ============ ========== =============== ============ ========== =========== ===========
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
South Carolina Electric & Gas Company (Company), a public utility, is a
South Carolina corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation, a South Carolina corporation and a registered public utility
holding company within the meaning of the Public Utility Holding Company Act of
1935, as amended (PUHCA). The Company is engaged predominately 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 the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust
I. Intercompany balances and transactions between the Company, Fuel Company and
SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain affiliates to
purchase gas for resale to its distribution customers and to purchase electric
energy. The Company purchases all of its natural gas requirements from South
Carolina Pipeline Corporation (SCPC), and at December 31, 2001 and 2000, the
Company had approximately $23.0 million and $45.9 million, respectively, payable
to SCPC for such gas purchases. The Company purchases all of the electric
generation of Williams Station, which is owned by South Carolina Generating
Company (GENCO), under a unit power sales agreement. At December 31, 2001 and
2000 the Company had approximately $9.5 million and $8.3 million, respectively,
payable to GENCO for unit power purchases. Such unit power purchases, which are
included in "Purchased power," amounted to approximately $95.8 million, $100.2
million and $105.5 million in 2001, 2000 and 1999, respectively.
Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $0.7 million,
$1.1 million and $0.9 million in 2001, 2000 and 1999, respectively.
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. This accounting standard requires cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-regulated. As a result the Company has recorded, as of December 31, 2001,
approximately $217 million and $81 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $125 million and $71 million, respectively. The
electric and gas regulatory assets of approximately $52 million and $40 million,
respectively (excluding deferred income tax assets), are recoverable through
rates. The Public Service Commission of South Carolina (SCPSC) has reviewed and
approved most of the items shown as regulatory assets through specific orders.
Other items represent costs which were not yet approved for recovery by the
SCPSC, but are the subject of current or future filings. In recording these
costs as regulatory assets, management believes the costs will be allowable
under existing rate-making concepts that are embodied in current rate orders
received by the Company. However, ultimate recovery is subject to SCPSC
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 in the period the write-off would
be recorded, but it is not expected that cash flows or financial position would
be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and as adopted by the SCPSC.
D. Utility Plant
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, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station (Summer
Station), and the South Carolina Public Service Authority (Santee Cooper) are
joint owners of 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 $963.0 million and $965.0 million as of December 31, 2001 and
2000, respectively. Accumulated depreciation associated with the Company's share
of Summer Station was approximately $407.4 million and $387.7 million as of
December 31, 2001 and 2000, respectively. The Company's share of the direct
expenses associated with operating Summer Station is included in "Other
operation and maintenance" expenses.
As allowed by the SCPSC, the Company accrues in advance its portion of
estimated scheduled outage costs for Summer Station. Total outage costs for the
planned outage in April 2002 are estimated to be approximately $13 million, of
which the Company will be responsible for approximately $8.9 million. As of
December 31, 2001, the Company had accrued $5.9 million.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, 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 8.8%, 8.1% and
7.7% for 2001, 2000 and 1999, respectively. These rates do not exceed the
maximum allowable rate as calculated under FERC Order No. 561. Interest on
nuclear fuel in process is capitalized at the actual interest amount incurred.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services are
provided to customers and include estimated amounts for electricity and natural
gas delivered but not yet billed. Prior to January 1, 2000 revenues related to
regulated electric and gas services were recorded only as customers were billed
(see Note 2). Unbilled revenues totaled approximately $39.5 million and $44.9
million as of December 31, 2001 and 2000, respectively.
Fuel costs for electric generation are collected through the fuel cost
component in retail electric rates. The fuel cost component contained in
electric rates 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 fuel cost hearing. The Company had undercollected through
the electric fuel cost component approximately $47.4 million and $35.5 million
at December 31, 2001 and 2000, respectively, which are included in "Deferred
Debits - 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 gas
cost recovery hearing. At December 31, 2001 and 2000 the Company had
undercollected through the gas cost recovery procedure approximately $12.2
million and $12.7 million, respectively, which are included in "Deferred Debits
- - 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.
G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the
straight-line method and are based on the estimated service lives of the various
classes of property. The composite weighted average depreciation rates for
utility plant assets were 2.98%, 2.98% and 2.99% for 2001, 2000 and 1999,
respectively.
Nuclear fuel amortization, which is included in "Fuel used in electric
generation" and recovered through the fuel cost component of the Company's
rates, is recorded using the units-of-production method. 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.
H. Nuclear Decommissioning
The Company's share of estimated site-specific nuclear decommissioning
costs for Summer Station, including the cost of decommissioning plant components
not subject to radioactive contamination, totals approximately $357.3 million,
stated in 1999 dollars, based on a decommissioning study completed in 2000.
Santee Cooper is responsible for decommissioning costs related to its one-third
ownership interest in the station. The cost estimate is based on a
decommissioning methodology acceptable to the Nuclear Regulatory Commission
(NRC) under which the site would be maintained over a period of approximately 60
years in such a manner as to allow for subsequent decontamination that permits
release for unrestricted use.
The Company's method of funding decommissioning costs is referred to as
COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through
rates ($3.2 million in each of 2001, 2000 and 1999) are used to pay premiums on
insurance policies on the lives of certain Company personnel. The Company is the
beneficiary of these policies. Through these insurance contracts, the Company is
able to take advantage of income tax benefits and accrue earnings on the fund on
a tax-deferred basis. Amounts for decommissioning collected through electric
rates, insurance proceeds, and interest on proceeds, less expenses, are
transferred by the Company to an external trust fund in compliance with the
financial assurance requirements of the NRC. Management intends for the fund,
including earnings thereon, to provide for all eventual decommissioning
expenditures on an after-tax basis. The Company records its liability for
decommissioning costs in deferred credits.
In addition to the above, pursuant to the National Energy Policy Act
passed by Congress in 1992 and the requirements of the DOE, the Company has
recorded a liability for its estimated share of the DOE's decontamination and
decommissioning obligation. The liability, approximately $2.4 million at
December 31, 2001, has been included in "Long-Term Debt, net." The Company is
recovering the cost associated with this liability through the fuel cost
component of its rates; accordingly, this amount has been deferred and is
included in "Deferred Debits - Other."
I. Income Taxes
The Company is included in the consolidated Federal income tax return of
SCANA Corporation. 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 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, tax
benefits of the parent holding company are distributed in cash to tax paying
affiliates, including SCE&G, in the form of capital contributions. In 2001,
capital contributions of approximately $33 million were received by SCE&G under
such provisions.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium, discount and expense are being amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues. Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.
K. 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 primarily to regulated operations. Such amounts are deferred and
amortized with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $24.4
million and $20.2 million at December 31, 2001 and 2000, respectively. The
deferral includes the estimated costs associated with the matters discussed in
Note 12C.
L. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide emission
allowances are purchased and financed by Fuel Company under a contract which
requires the Company to reimburse Fuel Company for all costs and expenses
relating to the ownership and financing of fuel inventories and sulfur dioxide
emission allowances. Accordingly, such fuel inventories and emission allowances
and fuel-related assets and liabilities are included in the Company's
consolidated financial statements. (See Note 6.)
M. Temporary Cash Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments are generally in the form of commercial paper, certificates of
deposit and repurchase agreements.
N. New Accounting Standards
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" are effective January 1, 2002. This Statement requires that
one accounting model be used for long-lived assets to be disposed of by sale,
whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements from the initial
adoption of SFAS 144.
O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2001.
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. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues from cycle billing to full accrual. The cumulative effect
of this change was $22 million, net of tax. Accruing unbilled revenues more
closely matches revenues and expenses. Unbilled revenues represent the estimated
amount customers will be charged for service rendered but not yet billed as of
the end of the accounting period.
If this method had been applied retroactively, net income would have
been $191 million for the year ended December 31, 1999, compared to $189
million, as reported.
3. RATE AND OTHER REGULATORY MATTERS
Electric
On April 24, 2001 the SCPSC approved the Company's request to increase
the fuel component of rates charged to electric customers from 1.330 cents per
kilowatt-hour to 1.579 cents per kilowatt-hour. The increase reflects higher
fuel costs projected for the period May 2001 through April 2002. The increase
also provides recovery over a two-year period of under-collected actual fuel
costs through April 2001, including short-term purchased power costs
necessitated by outages at two of the Company's base load generating plants in
winter 2000-2001. The new rates were effective as of the first billing cycle in
May 2001.
On September 14, 1999 the SCPSC approved an accelerated capital recovery
plan for the Company's Cope Generating Station. The plan was implemented
beginning January 1, 2000 for a three-year period. The SCPSC approved an
accelerated capital recovery methodology wherein the Company may increase
depreciation of its Cope Generating Station in excess of amounts that would be
recorded based upon currently approved depreciation rates. The amount of the
accelerated depreciation will be determined by the Company based on the level of
revenues and operating expenses, not to exceed $36 million annually without the
approval of the SCPSC. Any unused portion of the $36 million in any given year
may be carried forward for possible use in the following year. As of December
31, 2001 no accelerated depreciation has been recorded. The accelerated capital
recovery plan will be accomplished through existing customer rates.
On January 9, 1996 the SCPSC authorized a return on common equity of
12.0 percent. The SCPSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over a ten-year
period. Additionally, the SCPSC approved accelerated amortization of a
significant portion of the Company's electric regulatory assets (excluding
deferred income tax assets) and the remaining transition obligation for
postretirement benefits other than pensions, which enabled the Company to
recover the balances as of the end of the year 2000.
Gas
The Company'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 the Company.
The Company's cost of gas component in effect during the years ended
December 31, 2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.993 January-February 2001 $.543 January-July 2000
$.793 March-October 2001 $.688 August-October 2000
$.596 November-December 2001 $.782 November-December 2000
On July 5, 2000 the SCPSC approved the Company's request to implement
lower depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million. The retroactive effect was
recorded in the second quarter of 2000.
In 1994 the SCPSC issued an order approving the Company's request to
recover through a billing surcharge to its gas customers the costs of
environmental cleanup at the sites of former manufactured gas plants (MGPs). The
billing surcharge is subject to annual review and provides for the recovery of
substantially all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations that had
previously been deferred. In October 2001, as a result of the annual review, the
SCPSC approved the Company's request to increase the billing surcharge from
1.1cents per therm to 3.0 cents per therm, which is intended to provide for the
recovery of the balance remaining at December 31, 2001 of $24.4 million prior to
the end of the year 2005.
Transit
In September 1992 the SCPSC issued an order granting the Company's
request for a $.25 increase in transit fares from $.50 to $.75 in Columbia,
South Carolina; however, the SCPSC also required $.40 fares for low income
customers and denied SCE&G's request for certain bus route and schedule changes.
The new rates were placed into effect in October 1992. After several appeals and
petitions for reconsideration to the South Carolina Circuit Court (Circuit
Court) and the South Carolina Supreme Court (Supreme Court) by the various
parties, on September 27, 2000 the SCPSC issued an order granting certain relief
requested by the Company. On September 29, 2000 the Consumer Advocate of South
Carolina (Consumer Advocate) filed a motion with the SCPSC for a stay of this
order. On October 3, 2000 the SCPSC accepted the Consumer Advocate's motion and
issued a stay of its order. The Consumer Advocate and other intervenors have
petitioned the Circuit Court for judicial review of the SCPSC's order granting
relief. The Circuit Court has held in abeyance any appellate review pending the
outcome of current negotiations on the transfer of the transit system from the
Company to an unaffiliated regional authority..
4. EMPLOYEE BENEFIT PLANS
The Company participates in SCANA's noncontributory defined benefit
pension plan, which covers substantially all permanent employees. SCANA's policy
has been to fund the plan to the extent permitted by the applicable Federal
income tax regulations as determined by an independent actuary.
Effective July 1, 2000, SCANA's pension plan was amended to provide a
cash balance formula. With certain exceptions, employees were allowed to either
remain under the final average pay formula or elect the cash balance formula.
Under the final average pay formula, benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment. Under the cash balance formula, the monthly benefit
earned under the final average pay formula at July 1, 2000 was converted to a
lump sum amount for each employee and increased by transition credits for
eligible employees. Under the cash balance formula, benefits based upon this
opening balance increase going forward as a result of compensation credits and
interest credits. The effect of this plan amendment was to reduce the Company's
net periodic benefit income for the year ended December 31, 2000 by
approximately $3.4 million.
In addition to pension benefits, the Company provides certain unfunded
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 the applicable benefits.
Effective July 1, 2000, PSNC's pension and postretirement benefit plans
were merged with SCANA's plans. At the time of the merger of the plans, PSNC had
recorded a prepaid pension cost of approximately $9.0 million and a
postretirement welfare plan obligation of approximately $9.1 million in its
consolidated balance sheet.
In connection with the joint ownership arrangements surrounding Summer
Station, as of December 31, 2001 the Company has recorded within deferred
credits an $8.4 million obligation to Santee Cooper, representing an estimate of
the net pension asset attributable to the Company's contributions to the plan
that were recovered through billings to Santee Cooper for its one-third portion
of shared costs. The Company has also recorded a $6.0 million receivable from
Santee Cooper representing an estimate of its portion of the unfunded net
postretirement benefit obligation.
As allowed by SFAS 87, 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," are set forth in the following tables:
Components of Net Periodic Benefit Cost
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
Millions of dollars 2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Service Cost $7.9 $8.3 $10.0 $3.0 $2.7 $3.0
Interest Cost 38.5 33.5 27.9 12.1 10.2 9.5
Expected return on assets (83.5) (76.6) (65.5) n/a n/a n/a
Prior service cost amortization 5.8 3.0 1.1 0.9 0.8 0.7
Actuarial (gain) loss (12.8) (12.2) (8.6) 0.7 - 1.2
Transition amount amortization 0.8 0.8 0.8 0.8 0.8 1.7
Special termination benefit cost - 5.5 - - 1.0
-
Amount attributable to Company
affiliates 2.2 1.7 1.1 (3.1)
---- --- ----- --- ----- --- ----- ----- ---
(1.6) (0.9)
Net periodic benefit (income) cost $(41.1) $(41.5) $(27.7) $14.4 $12.9 $16.2
====== ====== ====== = ===== ===== =====
Assumptions
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
As of December 31 2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Discount rate 7.5% 8.0% 8.0% 7.5% 8.0% 8.0%
Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Changes in Benefit Obligation
Retirement Benefits Other Postretirement Benefits
------------------------------- ---------------------------------------
Millions of dollars 2001 2000 2001 2000
---- ---- ---- ----
Benefit obligation, January 1 $479.3 $362.3 $139.0 $129.8
Service cost 7.9 8.3 3.0 2.7
Interest cost 38.5 33.5 12.1 10.2
Plan participants' contributions - 0.1 0.5 0.5
Plan amendment 21.5 65.4 1.2 0.9
Actuarial (gain) loss 19.6 1.6 20.1 (7.8)
Acquisition/merger of plans - 39.8 - 11.2
Benefits paid (36.0) (31.7) (9.2) (8.5)
-- ----- -- ----- ------ ---- ---- ----
Benefit obligation, December 31 $530.8 $479.3 $166.7 $139.0
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
----------------------------------------------
Millions of dollars 2001 2000
---- ----
Fair value of plan, assets, January 1 $894.3 $783.0
Actual return on plan assets (26.7) 96.7
Company contribution - -
Plan participants' contributions - 0.1
Acquisition/merger of plans - 46.2
Benefits paid (36.0) (31.7)
----- -- -----
Fair value of plan assets, December 31 $831.6 $894.3
====== ======
Funded Status of Plans
Retirement Benefits Other Postretirement Benefits
---------------------------------
Millions of dollars 2001 2000 2001 2000
----------- --------------------------- -----------------
Funded status, December 31 $300.8 $415.0 $(166.7) $(139.0)
Unrecognized actuarial (gain) loss (155.0) (297.6) 32.5 13.0
Unrecognized prior service cost 89.4 73.7 4.8 4.5
Unrecognized net transition obligation 4.0 4.8 7.4 8.3
-------- ----- --- ------- ---- ------ ---
Net amount recognized in
Consolidated Balance Sheet $239.2 $195.9 $(122.0) $(113.2)
====== ========= ======== ========
Health Care Trends
The determination of net periodic other postretirement benefit cost is based on
the following assumptions:
2001 2000 1999
- ----------------------------------------------- ---------- ----------
Health care cost trend rate 8.5% 7.5% 8.0%
Ultimate health care cost trend rate 5.0% 5.5% 5.5%
Year achieved 2009 2005 2005
The effect of a one-percentage-point increase or decrease in the assumed health
care cost trend rates on the aggregate of the service and interest cost
components of net periodic other postretirement health care benefit cost and the
accumulated other postretirement benefit obligation for health care benefits are
as follows:
1% 1%
Millions of dollars Increase Decrease
--------------- ----------------
Effect on health care cost $0.1 $(0.1)
Effect on postretirement obligation 1.6 (1.8)
5. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2002 through 2006 are summarized as follows:
- ---------------- ----------------- ------------------ -----------------
Year Amount Year Amount
- ---------------- ----------------- ------------------ -----------------
(Millions of dollars)
2002 $27.6 2005 $173.9
2003 123.7 2006 154.7
2004 123.9
- ---------------- ----------------- ------------------ -----------------
Approximately $23.5 million of the portion of long-term debt payable in
2002 may be satisfied by either deposit and cancellation of bonds issued upon
the basis of property additions or bond retirement credits, or by deposit of
cash with the Trustee.
On August 7, 1996 the City of Charleston executed 30-year electric and
gas franchise agreements with the Company. In consideration for the electric
franchise agreement, the Company is paying the City $25 million over seven years
(1996-2002) and has donated to the City the existing transit assets in
Charleston. The $25 million is included in electric plant-in-service.
The Company has three-year revolving lines of credit totaling $75
million, in addition to other lines of credit, that provide liquidity for
issuance of commercial paper. The three-year lines of credit provide back-up
liquidity when commercial paper outstanding is in excess of $175 million. The
Company's commercial paper outstanding totaled $114.7 million and $117.5 million
at December 31, 2001 and 2000, at weighted average interest rates of 1.95
percent and 6.59 percent, respectively.
Substantially all utility plant is pledged as collateral in connection
with long-term debt.
On January 31, 2002 the Company issued $300 million of first mortgage
bonds having an annual interest rate of 6.625 percent and maturing February 1,
2032. The proceeds from the sale of these bonds were used to reduce short-term
debt primarily incurred as a result of the Company's construction program and to
redeem its First and Refunding Mortgage Bonds, 8 7/8 percent Series due August
15, 2021.
6. FUEL FINANCINGS
Nuclear and fossil fuel inventories and sulfur dioxide emission
allowances are financed through the issuance by Fuel Company of short-term
commercial paper. These short-term borrowings are supported by a 364-day
revolving credit agreement which expires December 17, 2002. The credit agreement
provides for a maximum amount of $125 million to be outstanding at any time.
Since the credit agreement expires within one year, commercial paper amounts
outstanding have been classified as short-term debt.
Fuel Company commercial paper outstanding totaled $50.1 million and $70.2
million at December 31, 2001 and 2000, respectively, at weighted average
interest rates of 2.06 percent and 6.59 percent, respectively.
7. SHORT-TERM BORROWINGS
Details of lines of credit (including uncommitted lines of credit) and
short-term borrowings at December 31, 2001 and 2000, are as follows:
Millions of dollars 2001 2000
- -------------------------------------------------------- ---------------
Authorized lines of credit $300.0 $300.0
Unused lines of credit $300.0 $300.0
Short-term borrowings outstanding
Commercial paper (270 days or less) $164.8 $187.7
Weighted average interest rate 1.97% 6.59%
The Company pays fees to banks as compensation for its committed lines of
credit.
8. RETAINED EARNINGS
The Company's Restated Articles of Incorporation and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that, under
certain circumstances, could limit the payment of cash dividends on its common
stock. In addition, with respect to hydroelectric projects, the Federal Power
Act requires the appropriation of a portion of certain earnings therefrom. At
December 31, 2001 approximately $37 million of retained earnings were restricted
by this requirement as to payment of cash dividends on common stock.
9. PREFERRED STOCK
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend. Retirements under sinking fund
requirements are at par values. The aggregate annual amount of purchase fund or
sinking fund requirements for preferred stock for the years 2002 through 2006 is
$2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 2001, 2000 and 1999 are summarized as follows:
Number of Shares Millions of Dollars
- -------------------------------------------------------- -----------------------
Balance at December 31, 1998 240,052 $12.0
Shares Redeemed - $50 par value (8,565) (0.4)
- -------------------------------------------------------- -----------------------
Balance at December 31, 1999 231,487 11.6
Shares Redeemed - $50 par value (11,200) (0.6)
- -------------------------------------------------------- -----------------------
Balance at December 31, 2000 220,287 11.0
Shares Redeemed - $50 par value (10,803) (0.5)
- -------------------------------------------------------- -----------------------
Balance at December 31, 2001 209,484 $10.5
======================================================== =======================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned
subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55 percent
Trust Preferred Securities, Series A (the "Preferred Securities"). The Company
owns all of the Common Securities of the Trust (the "Common Securities"). The
Preferred Securities and the Common Securities (the "Trust Securities")
represent undivided beneficial ownership interests in the assets of the Trust.
The Trust exists for the sole purpose of issuing the Trust Securities and using
the proceeds thereof to purchase from the Company its 7.55 percent Junior
Subordinated Debentures due September 30, 2027. The sole asset of the Trust is
$50.0 million of Junior Subordinated Debentures of the Company. Accordingly, no
financial statements of the Trust are presented. The Company's obligations under
the Guarantee Agreement entered into in connection with the Preferred
Securities, when taken together with the Company's obligation to make interest
and other payments on the Junior Subordinated Debentures issued to the Trust and
the Company's obligations under the Indenture pursuant to which the Junior
Subordinated Debentures were issued, provides a full and unconditional guarantee
by the Company of the Trust's obligations under the Preferred Securities.
Proceeds were used to redeem preferred stock of the Company.
The preferred securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55 percent Junior Subordinated Debentures.
The Junior Subordinated Debentures will mature on September 30, 2027 and may be
redeemed, in whole or in part, at any time on or after September 30, 2002 or
upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received
from counsel experienced in such matters that there is more than an
insubstantial risk that: (1) the Trust is or will be subject to Federal income
tax, with respect to income received or accrued on the Junior Subordinated
Debentures, (2) interest payable by the Company on the Junior Subordinated
Debentures will not be deductible, in whole or in part, by the Company for
Federal income tax purposes, or (3) the Trust will be subject to more than a de
minimis amount of other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously be applied to redeem Preferred Securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The Preferred Securities are redeemable at $25 per
preferred security plus accrued distributions.
10. INCOME TAXES
Total income tax expense attributable to income (before cumulative effect
of accounting change) for 2001, 2000 and 1999 is as follows:
Millions of dollars 2001 2000 1999
- --------------------------------------------------------------- ----------------- -----------------
Current taxes:
Federal $83.8 $78.4 $91.3
State 10.2 7.8 0.3
- --------------------------------------------------------------- ----------------- -----------------
- --------------------------------------------------------------- ----------------- -----------------
Total current taxes 94.0 86.2 91.6
- --------------------------------------------------------------- ----------------- -----------------
- --------------------------------------------------------------- ----------------- -----------------
Deferred taxes, net:
Federal 8.7 31.8 7.7
State 1.6 5.2 1.4
- --------------------------------------------------------------- ----------------- -----------------
- --------------------------------------------------------------- ----------------- -----------------
Total deferred taxes 10.3 37.0 9.1
- --------------------------------------------------------------- ----------------- -----------------
- --------------------------------------------------------------- ----------------- -----------------
Investment tax credits:
Deferred - State 5.0 5.0 13.4
Amortization of amounts deferred - State (1.5) (1.3) (1.2)
Amortization of amounts deferred - Federal (3.2) (3.2) (3.2)
- --------------------------------------------------------------- ----------------- -----------------
Total investment tax credits 0.3 0.5 9.0
- --------------------------------------------------------------- ----------------- -----------------
Non-conventional fuel tax credits:
Deferred - Federal 18.7 9.4 n/a
- --------------------------------------------------------------- ----------------- -----------------
Total income tax expense $123.3 $133.1 $109.7
=============================================================== ================= =================
The difference between actual income tax expense and the amount calculated
from the application of the statutory 35 percent Federal income tax rate to
pre-tax income before cumulative effect of accounting change is reconciled as
follows:
Millions of dollars 2001 1999
2000
- ---------------------------------------------------------------- ----------------- ----------------- -----------------
Income before cumulative effect of accounting change $214.5 $223.9 $181.8
Total income tax expense:
Charged to operating expense 112.8 123.8 103.1
Charged to other items 10.5 9.3 6.6
Preferred stock dividends 11.2 11.2 11.2
- ---------------------------------------------------------------- ----------------- ----------------- -----------------
Total pre-tax income $349.0 $368.2 $302.7
================================================================ ================= ================= =================
================================================================ ================= ================= =================
Income taxes on above at statutory Federal income tax rate $122.2 $128.9 $106.0
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 9.9 10.9 9.0
Amortization of Federal investment tax credits (3.2) (3.2)
(3.2)
Other differences, net (5.6) (3.5)
(2.1)
- ---------------------------------------------------------------- ----------------- ----------------- -----------------
- ---------------------------------------------------------------- ----------------- ----------------- -----------------
Total income tax expense $123.3 $133.1 $109.7
================================================================ ================= ================= =================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $611.3 million at December 31, 2001 and
$604.1 million at December 31, 2000 (see Note 1I), are as follows:
Millions of dollars 2001 2000
- ------------------------------------------------------- ------------------
Deferred tax assets:
Nondeductible reserves $54.5 $49.0
Unamortized investment tax credits 56.7 57.3
Deferred compensation 22.9 23.2
Cycle billing 10.6 -
Other 6.2 -
- ------------------------------------------------------- ------------------
Total deferred tax assets 150.9 129.5
- ------------------------------------------------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 647.6 636.3
Pension plan benefit income 81.1 65.3
Deferred fuel costs 22.8 18.5
Cycle billing - 1.9
Other 10.7 11.6
- ------------------------------------------------------- ------------------
Total deferred tax liabilities 762.2 733.6
- ------------------------------------------------------- ------------------
Net deferred tax liability $611.3 $604.1
======================================================= ==================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of SCANA through 1995, has examined and proposed adjustments
to SCANA's 1996 and 1997 Federal returns, and is currently examining SCANA's
Federal returns for 1998, 1999 and 2000. The Company does not anticipate that
any adjustments which might result from these examinations will have a
significant impact on its results of operations, cash flows or financial
position.
11. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2001 and 2000 are as follows:
Millions of dollars 2001 2000
- ----------------------------------------------------------- --------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- ---------------------------------------------------------------------- ---------
Assets:
Cash and temporary cash investments $77.9 $77.9 $60.2 $60.2
Investments 6.5 6.5 6.4 6.4
Liabilities:
Short-term borrowings 164.8 164.8 187.7 187.7
Long-term debt 1,440.0 1,542.9 1,294.1 1,331.6
Preferred stock (subject to purchase
or sinking funds) 10.4 8.5 11.0 8.7
The following methods and assumptions were used to estimate the fair
value of the above classes of financial instruments:
o Cash and temporary cash investments, including commercial paper,
repurchase agreements, treasury bills and notes, are valued at
their carrying amount.
o Fair values of investments and long-term debt are based on quoted
market prices of the instruments or similar instruments. For debt
instruments for which there are no quoted market prices available,
fair values are based on net present value calculations. For
investments for which the fair value is not readily determinable,
fair value is considered to approximate carrying value. Settlement
of long-term debt may not be possible or may not be considered
prudent.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking funds) is
estimated on the basis of market prices.
o Potential taxes and other expenses that would be incurred in an
actual sale or settlement have not been taken into consideration.
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. The Company's
adoption did not have a material impact on the Company's results of operations,
cash flows or financial position.
12. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC notified the Company of its agreement with the
Company's plan to reinforce Lake Murray Dam in order to maintain the lake in
case of an extreme earthquake. Construction for the project and related
activities, which began in the third quarter of 2001, is expected to cost $250
million and be completed in 2005. Any costs incurred by the Company are expected
to be recoverable through electric rates.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public
liability for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $9.5 billion. Each
reactor licensee is currently liable for up to $88.1 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $10 million of the liability per reactor would be
assessed per year. The Company's maximum assessment, based on its two-thirds
ownership of Summer Station, would be approximately $58.7 million per incident,
but not more than $6.7 million per year.
The Company currently maintains policies (for itself and on behalf of
Santee Cooper) with Nuclear Electric Insurance Limited (NEIL). The policies,
covering the nuclear facility for property damage, excess property damage and
outage costs, permit 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
the Company'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. 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.
C. Environmental
In September 1992 the EPA notified the Company, among others, of its
potential liability for the investigation and cleanup of the Calhoun Park area
site in Charleston, South Carolina. This site encompasses approximately 30 acres
and includes properties which were locations for various industrial operations,
including one of the Company's decommissioned MGPs. Field work at the site began
in November 1993 and has required the submission of several investigative
reports and the implementation of several work plans. In September 2000, the
Company was notified by the South Carolina Department of Health and
Environmental Control (DHEC) that benzene contamination was detected in the
intermediate aquifer on surrounding properties of the Calhoun Park area site.
The EPA required that the Company conduct a focused Remedial
Investigation/Feasibility Study on the intermediate aquifer, which was completed
in June 2001. The EPA expects to issue a Record of Decision dealing with the
intermediate aquifer and sediments in June 2002. The Company anticipates that
major remediation activities will be completed in 2003, with certain monitoring
activities continuing until 2007. As of December 31, 2001, the Company has spent
approximately $15.8 million to remediate the Calhoun Park area site. Total
remediation costs are estimated to be $21.9 million.
The Company owns three other decommissioned MGP sites in South Carolina
which contain residues of by-product chemicals. Two of these sites are currently
being remediated under work plans approved by DHEC. The Company is continuing to
investigate the remaining site and is monitoring the nature and extent of
residual contamination. The Company anticipates that major remediation
activities for these three sites will be completed between 2003-2005. The
Company has spent approximately $2.0 million related to these sites, and expects
to incur an additional $6.0 million.
D. Franchise Agreement
See Note 5 for a discussion of the electric franchise agreement between
the Company and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its
business operations which management anticipates will be resolved without
material loss to the Company.
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 $9.0 million, $5.9 million and $4.5
million in 2001, 2000 and 1999, respectively. Future minimum rental payments
under such leases are as follows:
Millions of dollars
2002 $12.0
2003 11.5
2004 9.9
2005 9.4
2006 9.2
Thereafter 25.8
------
$77.8
G. Purchase Commitments
Purchase commitments for coal supply and other contracts are as follows:
2002 $166.7
2003 142.6
2004 60.4
2005 0.2
2006 0.2
Thereafter 10.6
-------
$380.7
13. 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. Non-regulated sales and
transfers are recorded at current market prices.
Electric Operations is comprised of the electric portion of the Company
and Fuel Company and is primarily engaged in the generation, transmission, and
distribution of electricity. The Company's electric service territory extends
into 24 counties covering more than 15,000 square miles in the central,
southern, and southwestern portions of South Carolina. Sales of electricity to
industrial, commercial, and residential customers are regulated by the SCPSC and
by FERC. Fuel Company acquires, owns, and provides financing for the fuel and
emission allowances required for the operation of the Company's generation
facilities.
Gas Distribution, comprised of the local distribution operations of the
Company, is engaged in the purchase and sale, primarily at retail, of natural
gas. The Company's operations extend to 33 counties in South Carolina covering
approximately 22,000 square miles.
The Company's reportable segments share a similar regulatory
environment and, in some cases, overlapping service areas. However, Electric
Operation's product differs from Gas Distribution, as does its generation
process and method of distribution.
Disclosure of Reportable Segments
Millions of dollars
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
Electric Gas All Adjustments/ Consolidated
2001 Operations Distribution Other Eliminations Total
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
External Customer Revenue $1,374 $341 - - $1,715
Intersegment Revenue 212 - - $(212) -
Operating Income (Loss) 405 26 - (3) 428
Interest Expense 3 n/a $4 106 109
Depreciation & Amortization 151 12 - - 163
Segment Assets 5,034 428 - (500) 4,962
Expenditures for Assets 409 16 - 4 429
Deferred Tax Assets - n/a - - -
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
Electric Gas All Adjustments/ Consolidated
2000 Operations Distribution Other Eliminations Total
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
External Customer Revenue $1,344 $325 $1 $(1) $1,669
Intersegment Revenue 218 2 - (220) -
Operating Income (Loss) 430 31 - (4) 457
Interest Expense 5 n/a 4 96 105
Depreciation & Amortization 147 11 - - 158
Segment Assets 4,655 416 - (400) 4,671
Expenditures for Assets 227 19 - 32 278
Deferred Tax Assets - n/a - - -
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
Electric Gas All Adjustments/ Consolidated
1999 Operations Distribution Other Eliminations Total
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
External Customer Revenue $1,226 $239 $2 $(2) $1,465
Intersegment Revenue 2 - (205)
203 -
Operating Income (Loss) 22 - (5) 393
376
Interest Expense n/a 4 93 102
5
Depreciation & Amortization 13 - - 153
140
Segment Assets 4,452 399 6 (447) 4,410
Expenditures for Assets 19 - 10 227
198
Deferred Tax Assets n/a - 14
2 16
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
Management uses operating income to measure segment profitability for
regulated operations. Accordingly, the Company does not allocate interest
charges or income tax expense (benefit) to its segments. Similarly, management
evaluates utility plant for its segments. Therefore, the Company does not
allocate accumulated depreciation, common and non-utility plant, or deferred tax
assets to reportable segments. Interest income is not reported by segment and is
not material.
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 revenue remove
revenues from non-reportable segments.
Segment assets include utility plant only (excluding accumulated
depreciation) for all segments. As a result, adjustments to assets include
accumulated depreciation, common and non-utility plant and non-fixed assets for
the segments.
Adjustments to Interest Expense and Deferred Tax Assets include
primarily the totals from the Company that are not allocated to the segments.
Interest Expense is also adjusted to eliminate inter-segment charges. Deferred
Tax Assets are also adjusted to remove the non-current portion of those assets.
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of Dollars
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
2001 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Total operating revenues $499 $400 $461 $355 $1,715
Operating income 110 88 145 85 428
Net income 54 43 80 45 222
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
2000 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Total operating revenues $395 $371 $448 $455 $1,669
Operating income 109 96 155 97 457
Income before cumulative effect of accounting change 55 44 82 50 231
Cumulative effect of accounting change, net of taxes 22 - - - 22
Net income 77 44 82 50 253
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
PUBLIC SERVICE COMPANY
OF NORTH CAROLINA, INCORPORATED
Item 7. Management's Narrative Analysis of Results of Operations......119
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.....123
Item 8. Financial Statements and Supplementary Data....................124
Public Service Company of North Carolina, Incorporated meets the conditions set
forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore is
filing this form with the reduced disclosure format allowed under General
Instruction I(2).
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
Statements included in this narrative analysis (or elsewhere in this
annual report) which are not statements of historical fact are intended to be,
and are hereby identified as, forward-looking statements for purposes of the
safe harbor provided by Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. 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) that the information is of a preliminary
nature and may be subject to further and/or continuing review and adjustment,
(2) changes in the utility regulatory environment, (3) changes in the economy,
especially in PSNC's service territory, (4) the impact of competition from other
energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in PSNC's accounting policies, (8) weather conditions,
especially in areas served by PSNC, (9) inflation, (10) changes in environmental
regulations, and (11) the other risks and uncertainties described from time to
time in PSNC's periodic reports filed with the SEC. PSNC disclaims any
obligation to update any forward-looking statements.
Net Income
Net income for the twelve months ended December 31, 2001 and 2000 was
as follows:
Millions of dollars 2001 2000
- ------------------------------------------------------------------------------
Net income derived from:
Continuing operations $14.7 $21.2
Cumulative effect of accounting change, net of taxes - 6.6
- ------------------------------------------------------------------------------
Net income $14.7 $27.8
==============================================================================
Net income from continuing operations decreased approximately $6.5
million, due to reduced margin, the sale of PSNC Production Corporation to
another SCANA subsidiary (see Note 4 of Notes to Consolidated Financial
Statements), higher operating expenses, lower income related to merchandise and
jobbing activities and increased interest expense. Reduced margin in 2001 was
partially attributable to rate reductions implemented in connection with the
NCUC's approval of SCANA's acquisition of PSNC and to decreases in usage
resulting from the slowing economy. Higher operating expenses were primarily
attributable to severance costs and increased bad debt experience arising from
record high gas costs early in the year. In 2000 the cumulative effect of an
accounting change resulted from the recording of unbilled revenues (See Note 2
of Notes to Consolidated Financial Statements).
The nature of PSNC's business is seasonal. The quarters ending March 31
and December 31 are generally PSNC's most profitable quarters due to increased
demand for natural gas related to lower space heating requirements.
PSNC's Board of Directors authorized payment of dividends on common
stock held by SCANA as follows:
Declaration Date Dividend Amount Quarter Ended Payment Date
February 22, 2001 $6.0 million March 31, 2001 April 1, 2001
May 3, 2001 $5.8 million June 30, 2001 July 1, 2001
August 2, 2001 $3.0 million September 30, 2001 October 1, 2001
Gas Distribution
Gas distribution sales margins for 2001 and 2000, excluding the
cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2001 2000 Change % Change
- -----------------------------------------------------------------------
Operating revenues $452.6 $405.6 $47.0 11.6%
Less: Cost of gas (286.1) (237.4) (48.7) 20.5%
- --------------------------------------------------------
Gross margin $166.5 $168.2 $(1.7) (1.0)%
=======================================================================
Gas distribution sales margin for the year ended December 31, 2001
decreased as a result of a $1 million reduction in rates in each of August 2000
and 2001 related to the acquisition of PSNC by SCANA (see Note 5-D of Notes to
Consolidated Financial Statements) and lower natural gas usage.
Energy Marketing
Effective January 1, 2001 PSNC Production Corporation and SCANA Public
Service Company LLC, both of which participated in nonregulated activities such
as natural gas marketing and supply management services, were sold to SCANA
Energy Marketing, Inc., a subsidiary of SCANA (see Note 4), and energy marketing
ceased to be a segment of PSNC's business.
Energy marketing operating revenues and net income (including
affiliated transactions) for the year ended December 31, 2000 were as follows:
Millions of dollars
------------------------------------------------- ------------------
Operating revenues $142.9
Net income 2.0
================================================= ==================
Operation and Maintenance Expenses
The $1.3 million increase in operation and maintenance expenses from
2000 is primarily due to severance costs and an increased provision for bad
debt.
Other Income, net
Other income decreased $1.9 million for the year ended December 31,
2001 as compared to the same period in 2000 primarily due to lower revenue and
income related to merchandise and jobbing activities. The sales of gas
appliances in 2001 were adversely impacted by the slowing economy and record
high gas prices early in the year.
Interest Expense
Interest expense increased $2.4 million over 2000 as a result of
increased borrowings and interest expense related to the operation of Rider D
(see Note 1-G of Notes to Consolidated Financial Statements). PSNC issued $150
million of medium-term notes on February 16, 2001. The proceeds from these
borrowings were used to reduce short-term debt.
Capital Expansion Program and Liquidity Matters
PSNC's capital expansion program includes the construction of lines,
systems and facilities and the purchase of related equipment. PSNC's 2002
construction budget is approximately $41 million, compared to actual
construction expenditures for 2001 of $75.3 million.
For the years 2003-2006, PSNC has an aggregate of $21.4 million of
long-term debt maturing. These obligations and other commitments are tabulated
below.
Contractual Cash Obligations
Less than After
December 31, 2001 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of dollars)
Long-term and short-term debt
(including interest) $582 $26 $78 $44 $434
Operating leases 1 1 - - -
Other commercial commitments 231 162 69 - -
Included in other commercial commitments are estimated obligations under
forward contracts for natural gas purchases. Certain of these contracts relate
to regulated gas businesses; therefore, the effects of such contracts on gas
costs are reflected in gas rates. The forward contracts for natural gas
purchases include customary "make-whole" or default provisions, but are not
considered to be "take-or-pay" contracts.
Financing Limits and Related Matters
PSNC's issuance of various securities including long-term and short-term
debt is subject to customary approval or authorization by state and Federal
regulatory bodies including the NCUC, the SEC and FERC. The following paragraphs
describe the financing programs currently utilized by PSNC.
PSNC finances its operations and capital needs through short-term and
long-term borrowings, including, from time-to-time, advances from SCANA. On
February 16, 2001, PSNC issued $150 million of medium term notes due February
15, 2011.
In late 2001 PSNC entered into two interest rate swap agreements to pay
variable rates and receive fixed rates on a combined notional amount of $44.9
million. (See Note 10 of Notes to Consolidated Financial Statements.)
PSNC utilitizes no off-balance sheet financings or similar arrangements
other than incidental operating leases, generally for office furniture and
equipment.
Competition
Although PSNC is the sole distributor of natural gas in its service
area, it faces competition from suppliers of alternate fuels. The primary
alternate fuels available to large commercial and industrial customers are fuel
oil and propane. The primary competition to natural gas in the residential and
smaller commercial markets is electricity.
The NCUC has approved a rate structure that allows PSNC to negotiate
reduced rates in order to match the cost of alternate fuels to large commercial
and industrial customers and recover the lost margin from other classes of
customers. PSNC anticipates that the need to negotiate reduced rates with these
customers will continue.
Electric restructuring efforts in North Carolina have been stalled by
developments in California, concerns over municipal power agencies' debt levels
and other factors. Legislation or regulatory action at the Federal level,
particularly as part of a larger energy policy initiative, may be considered in
2002. PSNC is not able to predict whether any restructuring legislation or
regulatory action will be enacted and, if it is, the impact it will have on PSNC
and the natural gas industry.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
SFAS 71 - PSNC is subject to the provisions of SFAS 71, 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.
Aside from other impacts which might be experienced as a result of deregulation
or other significant changes in the regulatory environments of the utilities,
SFAS 71 could cease to be applicable and PSNC could be required to write off
such regulatory assets and liabilities.
Provisions for bad debts / Allowances for doubtful accounts - As of each
balance sheet date, PSNC evaluates the collectibility of accounts receivable and
records allowances for doubtful accounts based on estimates of the level of
actual write-offs which might be experienced. These estimates are based on,
among other things, comparisons of the relative age of accounts and
consideration of actual write-off history.
Goodwill amortization and impairment analysis - SFAS 141, "Business
Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," were issued
during 2001. SFAS 141 will require all future acquisitions to be accounted for
utilizing the purchase method. PSNC considers the amounts categorized by FERC as
"acquisition adjustments" to be goodwill as defined in SFAS 142 and has ceased
amortization of such amounts upon the adoption of SFAS 142 effective January 1,
2002. In 2001 the amount of such amortization expense recorded was $13 million.
This amortization related to an acquisition adjustment of approximately $466
million.
As required by the provisions of SFAS 142, PSNC is performing an
initial valuation analysis to determine whether this carrying amount is impaired
and, if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement, PSNC will have completed the initial stage of the analysis by June
30, 2002. If a write-down is indicated by the analysis, it will be quantified
and recorded by the end of 2002. Because PSNC is in the early stages of the
analysis, the effect, if any, of the adoption of the impairment provisions of
the Statement is not known; however, if a write-down is considered necessary, it
could be material to PSNC's results of operations for 2002.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset. PSNC will adopt SFAS 143 effective January 1,
2003. The impact SFAS 143 may have on PSNC's results of operations, cash flows
or financial position has not been determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," are effective January 1, 2002. This Statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on PSNC's financial statements from the initial adoption of
SFAS 144.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by PSNC described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about PSNC's
financial instruments that are sensitive to changes in interest rates. For debt
obligations, the table presents principal cash flows and related weighted
average interest rates by expected maturity dates.
December 31, 2001 Expected Maturity Date
Millions of dollars
Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value
---------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- ------------
Long-Term Debt:
Fixed Rate ($) 4.3 7.5 7.5 3.2 3.2 269.2 294.9 298.4
Average Fixed Interest Rate 10.0 9.47 9.47 8.75 8.75 7.0 7.2
Interest Rate Swap:
Pay Variable/Receive Fixed ($) - - 12.9 - - 32.0 44.9 (0.1)
Average Pay Interest Rate - - 7.82 - - 5.26 6.00
Average Receive Interest Rate - - 10.0 - - 8.75 9.10
December 31, 2000 Expected Maturity Date
Millions of dollars
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value
---------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- ------------
Long-Term Debt:
Fixed Rate ($) 4.3 4.3 7.5 7.5 3.2 122.4 149.2 154.9
Average Fixed Interest Rate 10.0% 10.0% 9.47% 9.47% 8.75% 7.50% 7.87%
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Reports........................................ 124
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2001 and 2000.......... 126
Consolidated Statements of Income for the
Years Ended December 31, 2001 and 2000, the Three Months Ended
December 31, 1999 and the Fiscal Year Ended September 30, 1999..... 127
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001 and 2000, the Three Months Ended
December 31, 1999 and the Fiscal Year Ended September 30, 1999.... 128
Consolidated Statements of Capitalization as of
December 31, 2001 and 2000......................................... 129
Consolidated Statements of Common Equity for the Years
Ended December 31, 2001 and 2000, the Three Months Ended
December 31, 1999 and the Fiscal Year Ended September 30, 1999..... 130
Notes to Consolidated Financial Statements..............................131
INDEPENDENT AUDITORS' REPORT
Public Service Company of North Carolina, Incorporated:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of Public Service Company of North Carolina, Incorporated
(Company) as of December 31, 2001 and 2000, and the related Consolidated
Statements of Income, Common Equity and of Cash Flows for the years then ended
and for the three months ended December 31, 1999. Our audits also included the
financial statement schedule listed in Part IV at Item 14. 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. The
consolidated financial statements of the Company for the fiscal year ended
September 30, 1999 were audited by other auditors whose report, dated November
4, 1999 (except with respect to matters discussed in Note 13, as to which the
date is December 17, 1999), expressed an unqualified opinion on those
statements.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 the Company at December 31, 2001
and 2000, and the results of its operations and its cash flows for the years
then ended and for the three months ended December 31, 1999 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 Notes 1D and 2, respectively, to the consolidated financial
statements, effective January 1, 2000, the Company changed its fiscal year end
to December 31 and changed its method of accounting for operating revenues
associated with its regulated utility operations.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 8, 2002
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of Public Service Company of
North Carolina, Incorporated included in this Form 10-K, and have issued our
report thereon dated November 4, 1999 (except with respect to the matters
discussed in Note 13, as to which the date is December 17, 1999).
Our audit was made for the purpose of forming an opinion on those
statements taken as a whole. The schedules listed in the index are the
responsibility of the Registrant's management and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
s/Arthur Andersen LLP
Charlotte, North Carolina
November 4, 1999
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------- ------------------------ --------------------------
December 31, (Millions of dollars) 2001 2000
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Assets
Gas Utility Plant (Note 1) $855 $787
Less accumulated depreciation 288 263
Acquisition adjustment, net of accumulated amortization (Notes 1 & 3) 439 452
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Gas Utility Plant, Net 1,006 976
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Nonutility Property and Investments, Net 29 34
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Current Assets:
Cash and temporary investments (Note 1) 18 8
Restricted cash and temporary investments (Note 1) 5
2
Receivables (net of allowance for uncollectible accounts
of $1.4 for 2001 and $2.4 for 2000) 70 144
Receivables - affiliated companies 12 4
Inventories (at average cost):
Stored gas 47 32
Materials and supplies 8 7
Other - 2
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Total Current Assets 157 202
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Deferred Charges and Other Assets:
Due from affiliate-pension asset (Note 6) 11 10
Regulatory assets 11 21
Other 7 10
- ---------------------------------------------------------------------------- --------------------------
------------------------
Total Deferred Charges and Other Assets 29 41
- ---------------------------------------------------------------------------- --------------------------
------------------------
Total $1,221 $1,253
============================================================================ ======================== ==========================
============================================================================ ==========================
Capitalization and Liabilities
Capitalization:
Common equity $715 $712
Long-term debt, net (Notes 7 & 10) 290 145
------------------------
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Total Capitalization 1,005 857
- ---------------------------------------------------------------------------- ------------------------ --------------------------
------------------------
Current Liabilities:
Short-term borrowings (Notes 8 & 10) - 125
Current portion of long-term debt (Note 7) 4 4
Accounts payable 41 82
Accounts payable - affiliated companies 10 2
Taxes accrued 5 3
Customer prepayments and deposits 17 8
Advances from parent - 44
Dividends declared and interest accrued 6 5
Other 3 6
- ---------------------------------------------------------------------------- ------------------------ --------------------------
------------------------
Total Current Liabilities 86 279
- ---------------------------------------------------------------------------- ------------------------ --------------------------
------------------------
Deferred Credits and Other Liabilities:
Deferred income taxes, net (Notes 1 & 9) 86 82
Deferred investment tax credits (Notes 1 & 9) 2 3
Due to affiliate-postretirement benefits (Note 6) 11 10
Regulatory liabilities 14 -
Other 17 22
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Total Deferred Credits and Other Liabilities 130 117
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Commitments and Contingencies (Note 11) - -
- ---------------------------------------------------------------------------- ------------------------ --------------------------
Total $1,221 $1,253
============================================================================ ======================== ==========================
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
- ------------------------------------------------------------------- -------------------------------- -------------------------------
Successor Predecessor
- ------------------------------------------------------------------- -------------------------------- ----------------- -------------
Three Months
Year Ended Ended Year Ended
December 31, December 31, September 30,
Millions of dollars 2001 2000 1999 1999
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Operating Revenues (Note 1 & 2) $453 $547 $81 $298
Cost of Gas 286 375 41 133
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Gross Margin 167 172 40 165
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Operating Expenses:
Operation and maintenance 69 67 18 71
Depreciation and amortization (Note 1) 43 42 7 26
Other taxes 6 6 2 15
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Total Operating Expenses 118 115 27 112
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Operating Income 49 57 13 53
Other Income, net 6 8 1 6
Interest Charges, net 22 20 5 18
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Income Before Income Taxes and
Cumulative Effect of Accounting Change 33 45 9 41
Income Taxes (Note 9) 18 24 4 17
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Income Before Cumulative Effect of Accounting Change 15 21 5 24
Cumulative Effect of Accounting Change, net of taxes (Note 2) - 7 - -
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
- ------------------------------------------------------------------- ---------------- --------------- ----------------- -------------
Net Income 15 28 5 24
=================================================================== ================ =============== ================= =============
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------- ---------------------------------- -------------------------------
Successor Predecessor
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Three Months
Year Ended Ended Year Ended
December 31, December 31, September 30,
Millions of dollars 2001 2000 1999 1999
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Cash Flows From Operating Activities:
Net income $15 $28 $5 $24
Adjustments to reconcile net income to net cash provided
from (used in) operating activities:
Cumulative effect of accounting change, net of taxes - (7) - -
Depreciation and amortization 50 47 8 29
Excess distributions (undistributed earnings) of 3 (3) (1) (1)
investee
Gain on sale of assets - (1) - -
Over (under) collection, fuel adjustment clause 23 7 1 (5)
Change in certain assets and liabilities:
(Increase) decrease in receivables, net 54 (70) (45) (4)
(Increase) decrease in inventories (15) (3) - (5)
(Increase) decrease in regulatory assets 1 (5) - (3)
Increase (decrease) in accounts payable and advances (68) 78 25 5
Increase (decrease) in accrued pension cost - - (1) (3)
Increase (decrease) in deferred income taxes, net 3 3 - 8
Other, net 14 - - 4
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Net Cash Provided From (Used In) Operating Activities 80 74 (8) 49
- ----------------------------------------------------------------- ----------------- ---------------- ------------
------------------
Cash Flows From Investing Activities:
Construction expenditures (75) (39) (12) (44)
Increase in investments - (1) - (9)
Proceeds on sale of assets 1 8 - -
Nonutility and other - - 1 5
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Net Cash Used In Investing Activities (74) (32) (11) (48)
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Cash Flows From Financing Activities:
Proceeds from issuance of common stock - - - 6
Proceeds from issuance of medium-term notes 148 - - -
Capital contribution from parent 3 - - -
Retirement of long-term debt and common stock (4) (9) (8) (17)
Dividend payments on common stock (18) (21) (5) (20)
Short-term borrowings, net ( 125) (13) 34 34
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Net Cash Provided From (Used In) Financing Activities 4 (43) 21 3
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Net Increase (Decrease) in Cash and Temporary Investments 10 (1) 2 4
Cash and Temporary Investments at Beginning of Period 8 9 7 3
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------ ------------
Cash and Temporary Investments at End of Period $18 $8 $9 $7
================================================================= ================= ================ ================== ============
Supplemental Cash Flow Information:
Cash paid during the period for:
Interest (net of capitalized interest of $1.2, $1.0,
$0.1 and $0.6) $16 $21 $5 $18
Income taxes 12 25 - 7
In connection with the acquisition of Public Service Company of North Carolina,
Inc. by SCANA Corporation, $21 million in common stock was cancelled. The
application of push-down accounting for the acquisition resulted in a $466
million acquisition adjustment.
Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service
Company LLC were sold to SCANA Energy Marketing, Inc., an affiliate, for $4.4
million, which approximated net book value. Assets transferred included
approximately $4.0 million in cash.
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ------------------------------------------------------------------------------------ -------------- ---------------
December 31, (Millions of dollars) 2001 2000
- ------------------------------------------------------------------------------------ -------------- ---------------
Common Equity:
Common stock, $1 par, 1,000 shares authorized and issued in 2001 and 2000 - -
Capital in excess of par value $706 $703
Retained earnings 9 9
--------------
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Common Equity 715 712
- ------------------------------------------------------------------------------------ -------------- ---------------
--------------
Long-term Debt:
Senior debentures (unsecured):
10% due 2004 12 17
8.75% due 2012 32 32
6.99% due 2026 50 50
7.45% due 2026 50 50
Medium-term notes:
6.625% due 2011 150 -
- ------------------------------------------------------------------------------------ -------------- ---------------
--------------
294 149
Less - Current maturities (4) (4)
--------------
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Long-Term Debt, Net 290 145
- ------------------------------------------------------------------------------------ -------------- ---------------
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Capitalization $1,005 $857
==================================================================================== ============== ===============
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF COMMON EQUITY
Capital Total
Millions of dollars Common Stock in Excess Retained Common
Shares Amount of Par Earnings Equity
- --------------------------------------------- --------------- --------- -------------- ------------ ---------------
Balance at September 30, 1998 20,274,332 $20 $133 $70 $223
Issuance of Stock 303,635 1 6 7
Net Income 24 24
Cash Dividends Declared (21) (21)
- --------------------------------------------- --------------- --------- -------------- ------------ ---------------
Balance at September 30, 1999 20,577,967 21 139 73 233
Net Income 5 5
Cash Dividends Declared (6) (6)
- --------------------------------------------- --------------- --------- -------------- ------------ ---------------
Balance at December 31, 1999 20,577,967 21 139 72 232
Cancellation of Shares Due to Acquisition (20,576,967) (21) 564 (72) 471
Net Income 28 28
Cash Dividends Declared (19) (19)
- --------------------------------------------- --------------- --------- -------------- ------------ ---------------
Balance at December 31, 2000 1,000 - 703 9 712
Capital Contributions From Parent 3 3
Net Income 15 15
Cash Dividends Declared (15) (15)
- --------------------------------------------- --------------- --------- -------------- ------------ ---------------
- --------------------------------------------- --------------- --------- -------------- ------------
Balance at December 31, 2001 1,000 $- $706 $9 $715
============================================= =============== ========= ============== ============ ===============
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
Public Service Company of North Carolina, Incorporated (Company), a
public utility, was organized as a North Carolina corporation in 1938. Effective
January 1, 2000 the acquisition of the Company by SCANA Corporation (SCANA), a
South Carolina holding company, was consummated in a business combination
accounted for as a purchase. As a result, the Company became a wholly owned
subsidiary of SCANA, incorporated under the laws of South Carolina. The Company
is engaged predominantly in the purchase, sale, transportation and distribution
of natural gas to residential, commercial and industrial customers in North
Carolina.
The accompanying Consolidated Financial Statements include the accounts
of the Company and its subsidiary companies, Clean Energy Enterprises, Inc.,
PSNC Blue Ridge Corporation, and PSNC Cardinal Pipeline Company (collectively,
the "Company"). In periods prior to 2001, the accounts of PSNC Production
Corporation are also included. Similarly, in 2000 the accounts of SCANA Public
Service Company LLC are included. PSNC Production Corporation and SCANA Public
Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of
SCANA, effective January 1, 2001 (see Note 4). Investments in other affiliates
in which the Company has the ability to exercise influence over operating and
financial policies are accounted for under the equity method. Significant
intercompany balances and transactions have been eliminated in consolidation.
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. This accounting standard requires cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-regulated. As a result, the Company has recorded, as of December 31, 2001,
approximately $10.6 million and $14.2 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred income tax
liabilities of approximately $.4 million. The regulatory assets are recoverable
through rates. 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 in the period the write-off would
be recorded, but it is not expected that cash flows or financial position would
be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by the National Association of
Regulatory Utility Commissioners (NARUC) and as adopted by the North Carolina
Utilities Commission (NCUC).
D. Change in Fiscal Year
The Company changed its fiscal year end to December 31 from September
30, effective January 1, 2000.
E. Utility Plant
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, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
F. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, 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 7.0 percent
and 6.8 percent for the years ended December 31, 2001 and 2000, respectively,
6.4 percent for the three months ended December 31, 1999 and 5.5 percent for the
fiscal year ended September 30, 1999. These rates do not exceed the maximum
allowable rate as calculated under FERC Order No. 561.
G. Revenue Recognition
Revenues are recorded during the accounting period in which services
are provided to customers, and include estimated amounts for natural gas
delivered, but not yet billed. Prior to January 1, 2000 revenues related to
regulated gas services were recorded only as customers were billed. (See Note
2.) Unbilled revenues totaled approximately $20.2 million and $48.4 million as
of December 31, 2001 and 2000, respectively.
The Company's Rider D mechanism authorizes the recovery of all
prudently incurred gas costs from customers on a monthly basis. Any difference
in amounts paid and collected for these costs is deferred for subsequent refund
to or collection from customers, with interest. Additionally, the Company can
recover its margin losses on negotiated gas sales to certain large
commercial/industrial customers in any manner authorized by the NCUC. Pursuant
to the operation of Rider D, the Company had overcollected from customers
approximately $13.8 million at December 31, 2001 and undercollected from
customers approximately $9.3 million at December 31, 2000.
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. The
Company establishes its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas as approved
by the NCUC.
H. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the
straight-line method and are based on the estimated service lives of the various
classes of property. The composite weighted average depreciation rates for
utility plant assets were 4.1 percent for the years ended December 31, 2001 and
2000, 4.1 percent for the three months ended December 31, 1999 and 3.9 percent
for the fiscal year ended September 30, 1999.
The acquisition adjustment related to the purchase of the Company by
SCANA is being amortized over a 35-year period using the straight-line method.
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," on January
1, 2002. See Note 1M for further discussion.
I. Income Taxes
The Company is included in the consolidated Federal income tax return
of SCANA Corporation for 2001 and 2000. 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
rates. Deferred tax assets and liabilities are adjusted for changes in such
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, tax benefits of the parent holding company are
distributed in cash to tax paying affiliates, including PSNC, in the form of
capital contributions. In 2001 capital contributions of $3.1 million were
received by PSNC under such provisions.
J. Debt Expense
The Company amortizes issuance costs for its debentures over the
life of the related debt. The Company is amortizing the redemption premium and
the unamortized issuance costs on its previously refunded Series K First
Mortgage Bonds over 15 years (1987-2002), in accordance with the treatment
authorized by the NCUC.
K. Environmental
The Company maintains an environmental assessment program to identify
and evaluate current and former operation 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 cleanup 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 to regulated operations. Such amounts are deferred and amortized
with recovery provided through rates.
L. Cash and Temporary Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments may include repurchase agreements, U.S. Treasury bills, federal
agency securities, certificates of deposit and high-grade commercial paper.
Since fiscal 1992, the Company has received refunds from its pipeline
transporters for which the investment and use have been restricted by an order
of the NCUC. Pursuant to an order of the NCUC, these funds are segregated from
the Company's general funds and will be used for expansion of the Company's
facilities into unserved territories. These refunds, along with interest earned
thereon, are periodically transferred to the Office of the State Treasurer of
North Carolina. The balance not transferred is reported in restricted cash and
temporary investments.
At December 31, 2000 the balance in restricted cash and temporary
investments included approximately $4.5 million in supplier refunds which was
returned to customers in the form of a bill credit during the first quarter of
2001. This refund to customers was approved by the NCUC to help defray the
record high natural gas prices during early 2001.
M. New Accounting Standards
SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other
Intangible Assets," were issued during 2001. SFAS 141 will require all future
acquisitions to be accounted for utilizing the purchase method. The Company
considers the amounts categorized by FERC as "acquisition adjustments" to be
goodwill as defined in SFAS 142 and has ceased amortization of such amounts upon
the adoption of SFAS 142 effective January 1, 2002. In 2001, the amount of such
amortization expense recorded was $13 million. This amortization related to the
acquisition adjustment of approximately $466 million carried on the books of the
Company.
As required by the provisions of SFAS 142, the Company is performing an
initial valuation analysis to determine whether this carrying amount is impaired
and, if so, the amount of any write-down which might be recorded as the
cumulative effect of the change in accounting principle. As allowed by the
Statement, the Company will have completed the initial stage of the analysis by
June 30, 2002. If a write-down is indicated by the analysis, it will be
quantified and recorded by the end of 2002. Because the Company is in the early
stages of the analysis, the effect, if any, of the adoption of the impairment
provisions of the Statement is not known; however, if a write-down is considered
necessary, it could be material to the Company's results of operations for 2002.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
guidance for recording and disclosing a liability related to the future
obligation to retire an asset (such as a nuclear plant). The Company will adopt
SFAS 143 effective January 1, 2003. The impact SFAS 143 may have on the
Company's results of operations, cash flows or financial position has not been
determined but could be material.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," are effective January 1, 2002. This Statement requires
that one accounting model be used for long-lived assets to be disposed of by
sale, whether previously held and used or newly acquired, and broadens the
presentation of discontinued operations to include more disposal transactions.
There was no impact on the Company's financial statements for the initial
adoption of SFAS 144.
N. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2001.
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 amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues from cycle billing to full accrual. The cumulative effect
of this change was $6.6 million, net of tax. Accruing unbilled revenues more
closely matches revenues and expenses. Unbilled revenues represent the estimated
amount customers will be charged for service rendered but not yet billed as of
the end of the accounting period. Also, effective January 1, 2000, the gas costs
associated with unbilled revenues are no longer deferred.
If this method had been applied retroactively, net income would have
been $11.0 million for the three months ended December 31, 1999, compared to
$5.1 million , as previously reported. Further, if this method had been applied
retroactively to the fiscal year ended September 30, 1999, the impact on that
year's net income would not have been material.
3. ACQUISITION BY SCANA CORPORATION
On February 10, 2000 the acquisition of the Company by SCANA was
consummated in a business combination accounted for as a purchase. As a result
the Company became a wholly owned subsidiary of SCANA. Pursuant to the Agreement
and Plan of Merger, Company shareholders were paid approximately $212 million in
cash and 17.4 million shares of SCANA common stock valued at approximately $488
million.
The Company has recorded a utility plant acquisition adjustment of
approximately $466 million, which reflects the excess of SCANA's purchase price
of approximately $700 million over the fair value of the Company's net assets at
January 1, 2000. The adjustment is being amortized over 35 years on the
straight-line basis. Common equity at December 31, 2001 and 2000 reflects the
effect of this acquisition adjustment. Adoption of SFAS 142 effective January 1,
2002 has resulted in the cessation of this amortization ($13 million per year)
and requires the periodic determination as to whether the carrying value has
suffered an impairment in value. As described in Note 1M, the Company will
determine whether there is an indication of an impairment by June 30, 2002 and
will record an impairment charge, if warranted, via a cumulative effect
adjustment, by the end of 2002.
In connection with the acquisition, severance benefits of approximately
$5.0 million have been paid to nine key executives. In addition, approximately
$3.1 million was paid to former directors of the Company in connection with
deferred compensation and retirement plans, and approximately $8.1 million was
paid to participants in the Company's nonqualified stock option plans.
4. ACQUISITION OF SONAT PUBLIC SERVICE COMPANY
Effective December 31, 1999 PSNC Production Corporation (PSNC
Production), a wholly owned subsidiary of the Company, purchased the remaining
50% membership interest in Sonat Public Service Company L.L.C. (Sonat) for $5.3
million. As a result, Sonat became a wholly owned subsidiary of PSNC Production.
Sonat was subsequently renamed SCANA Public Service Company LLC (SCANA Public
Service).
Effective January 1, 2001 PSNC Production and SCANA Public Service were
sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, for $4.4 million,
which approximated their net book value.
5. RATE AND OTHER REGULATORY MATTERS
A. The Company'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 and changes in the rates charged by the
Company's pipeline transporters. The Company may file revised tariffs with the
NCUC coincident with these changes or it may track the changes in its deferred
accounts for subsequent rate consideration. The NCUC reviews the Company's gas
purchasing practices annually.
The Company's benchmark cost of gas in effect during the years ended
December 2001 and 2000 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.690 January 2001 $.300 January 2000
$.750 February-March 2001 $.265 February-May 2000
$.650 April-August 2001 $.350 June 2000
$.500 September-October 2001 $.450 July-September 2000
$.350 November-December 2001 $.490 October-December 2000
B. On April 6, 2000 the NCUC issued an order permanently approving the
Company's request to establish its commodity cost of gas for large commercial
and industrial customers on the basis of market prices for natural gas. This
mechanism allows the Company to collect from its customers amounts approximating
the amounts paid for natural gas.
C. A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from the Company's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 the Company filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. On June 29, 2000 the NCUC approved the Company's
requests for disbursement of up to $28.4 million from the Company's expansion
fund for this project. The Company estimates that the cost of this project will
be approximately $31.4 million. The Madison County portion of the project was
completed at a cost of approximately $5.8 million and customers began receiving
service in July 2001.
D. On December 7, 1999 the NCUC issued an order approving SCANA's
acquisition of the Company. As specified in the NCUC order, the Company reduced
its rates by approximately $1 million in each of August 2000 and August 2001,
and agreed to a moratorium on general rate cases until August 2005. General rate
relief can be obtained during this period to recover costs associated with
materially adverse governmental actions and force majeure events.
E. On February 22, 1999 the NCUC approved the Company's application to
use expansion funds to extend natural gas service into Alexander County and
authorized disbursements from the fund of approximately $4.3 million . Most of
Alexander County lies within the Company's certificated service territory and
did not previously have natural gas service. The project was completed at a cost
of approximately $4.8 million, and customers began receiving natural gas service
in March 2000.
6. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS
Employee Benefit Plans
Since July 1, 2000 the Company has participated in SCANA's
noncontributory defined benefit pension plan, which covers substantially all
permanent employees. SCANA's pension plan benefits for the Company employees are
calculated using a cash balance formula under which employees earn benefits
through monthly compensation and interest credits. SCANA's policy has been to
fund the plan to the extent permitted by the applicable Federal income tax
regulations as determined by an independent actuary. Also since July 1, 2000,
the Company has participated in SCANA's plan to provide certain unfunded health
care and life insurance benefits to active and retired employees. Retirees share
in a portion of their medical care cost and are provided life insurance benefits
at no charge. The cost of postretirement benefits other than pensions are
accrued during the years the employees render the service necessary to be
eligible for the applicable benefits.
Prior to July 1, 2000 the Company and its subsidiaries sponsored a
noncontributory defined benefit pension plan covering substantially all
employees. The benefits were based on years of service and the employee's
compensation during the five consecutive years of employment that produced the
highest average pay. Contributions to the plan were determined on an annual
basis, with the amount of such contributions being within the range of the
minimum required funding amount and the maximum amount deductible for Federal
income tax purposes. Prior to July 1, 2000 the Company also provided certain
health care and life insurance benefits to its employees. Retirees were required
to contribute toward the costs of their medical care coverage. The costs of
postretirement benefits other than pensions were accrued during the years the
employees rendered the service necessary to be eligible for the applicable
benefits.
During the fiscal year ended September 30, 1999, the Company recognized
pension gains of $1.8 million and a net curtailment loss on postretirement
benefit obligations of $0.5 million directly related to severance activity under
restructuring discussed further in Note 12.
The fair value of the Company's common stock held by its plan at June
30, 2000, December 31, 1999, and September 30, 1999 measurement dates were
approximately $0.0 million, $1.4 million and $1.3 million respectively.
As discussed above, effective July 1, 2000, the Company's pension and
postretirement plans were merged with SCANA's plans. At the time of the plan
mergers, the Company had recognized a prepaid pension cost of approximately $9.0
million and a postretirement welfare plan obligation of approximately $9.1
million. For the period July 1 through December 31, 2000, the Company's net
periodic benefit income was approximately $0.6 million for the pension plan and
the Company's net periodic benefit cost was approximately $0.7 million for the
postretirement plan. For the years ended December 31, 2001 net periodic benefit
income was approximately $1.2 million for the pension plan and the Company's net
periodic benefit cost was approximately $2.0 million for the postretirement
plan.
Disclosures required for these plans under SFAS 132, "Employer's
Disclosures about Pensions and Other Postretirement Benefits," for relevant
periods prior to the Plan mergers, are set forth in the following tables:
Components of Net Periodic Benefit Cost:
Retirement Benefits Other Postretirement Benefits
------------------------------------ -----------------------------------
6 months 3 months 6 months 3 months
ended ended Fiscal ended ended Fiscal
June 30, Dec. 31, Year June 30, Dec. 31, Year
Millions of Dollars 2000 1999 1999 2000 1999 1999
---- - ---- ---- ---- - ---- ----
Service Cost $0.8 $ 0.5 $ 2.3 $ 0.1 $ 0.1 $ 0.3
Interest Cost 1.6 0.8 3.0 0.4 0.2 0.6
Expected return on plan assets (2.2) (0.8) (3.1) n/a n/a n/a
Prior Service Cost Amortization - 0.1 0.6 - - 0.1
Transition Amount Amortization - (0.1) (0.3) - - 0.2
------ - ----- ------ ------ - ------ - --- ---
Net periodic benefit cost $0.2 $ 0.5 $ 2.5 $ 0.5 $ 0.3 $ 1.2
==== ===== == ===== ===== ===== =====
Assumptions:
Retirement Benefits Other Postretirement Benefits
-------------------------------------------- ---------------------------------------
6 months 3 months 6 months 3 months
ended ended Fiscal ended ended Fiscal
June 30, Dec. 31, Year June 30, Dec. 31, Year
2000 1999 1999 2000 1999 1999
---- ---- ---- ---- ---- ----
Discount rate 8.00 % 8.00 % 7.50 % 8.00 % 8.00 % 7.50 %
Expected return on plan assets 9.50 % 9.50 % 8.00 % n/a n/a n/a
Rate of compensation increase Age-related Age-related Age-related Age-related Age-related Age-related
Changes in Benefit Obligations:
Retirement Benefits Other Postretirement Benefits
-------------------------------------- ---------------------------------------
6 months 3 months 6 months 3 months
ended ended Fiscal ended ended Fiscal
June 30, Dec. 31, Year June 30, Dec. 31, Year
Millions of Dollars 2000 1999 1999 2000 1999 1999
---- ---- ---- ---- ---- ----
Benefit Obligation, beginning
of period $38.7 $44.1 $46.6 $ 8.9 $9.3 $9.0
Service Cost 0.8 0.5 2.3 0.1 - 0.3
Interest Cost 1.6 0.8 3.0 0.4 0.2 0.6
Settlement payments - - (7.2) n/a n/a n/a
Benefits paid (2.5) (2.2) (0.5) (0.3) (0.1) (0.6)
Curtailment gain - - (1.2) - - (0.3)
Actuarial (gain) loss 1.3 (4.5) 1.1 2.1 (0.5) 0.3
--- --- --- ---- --- --- ---- --- - ---- -- ---
Benefit Obligation at end of period $39.9 $38.7 $44.1 $ 11.2 $8.9 $9.3
===== ===== ===== ====== ==== ====
Change in Plan Assets:
Retirement Benefits
-------------------------------------------------------------------
6 months ended 3 months ended Fiscal
June 30, Dec. 31, Year
Millions of Dollars 2000 1999 1999
---- ---- ----
Fair value of plan assets, beginning of period $47.9 $45.0 $43.7
Actual return on plan assets 0.8 3.1 5.3
Company contribution - 2.0 3.7
Benefits paid (2.5) (2.2) (7.7)
- ---- -- ---- --- ----
Fair value of plan assets at end of period $46.2 $47.9 $45.0
===== ===== =====
Funded Status of Plans:
Retirement Benefits Other Postretirement Benefits
------------------------------------- ---------------------------------------
6 months 3 months 6 months 3 months
ended ended Fiscal ended ended Fiscal
June 30, Dec. 31, Year June 30, Dec. 31, Year
Millions of Dollars 2000 1999 1999 2000 1999 1999
---- ---- ---- ---- ---- ----
Funded status, beginning of period $6.3 $9.2 $0.9 $(11.2) $(8.9) $(9.3)
Unrecognized actuarial (gain) loss 2.7 (14.4) (7.6) 2.1 (0.5) 0.3
Unrecognized prior service cost - 2.5 2.7 - 0.4 0.4
Unrecognized transition obligation - (0.8) (1.0) - 2.7 2.8
----- - -- ---- -- ---- ------ -- --- --- ---- ---
Net amount recognized $9.0 $(3.5) $(5.0) $(9.1) $(6.3) $(5.8)
==== ====== = ====== ====== ====== ======
Health Care Trends
The determination of net periodic other postretirement benefit cost is
based on the following assumptions.
6 months ended June 3 months ended Fiscal Year
30, 2000 Dec. 31, 1999 1999
- ------------------------------------- --------------------------------------------------------
Health care cost trend rate 8.00 % 8.00 % 7.75 %
Ultimate health care cost trend rate 5.50 % 5.50 % 4.25 %
Year achieved 2005 2005 2008
Stock Compensation Plans
Prior to SCANA's acquisition of the Company effective January 1, 2000,
the Company sponsored the stock-based compensation plans described below. The
Company applied the intrinsic value method prescribed by Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related
interpretations in accounting for grants made under the plans. Because all
options granted after September 30, 1997 were granted with exercise prices equal
to the fair market value of the Company's stock on the respective grant dates,
no compensation expense was recognized in connection with such grants. If the
Company had determined compensation expense for the issuance of options based on
the fair value method described in SFAS 123, "Accounting for Stock-Based
Compensation," net income as reported of $24.5 million for the year ended
September 30, 1999 would have been reduced to the pro forma amount of $23.7
million.
Nonqualified Stock Option Plans
The Company sponsored a 1992 Nonqualified Stock Option Plan (1992 Plan)
and a 1997 Nonqualified Stock Option Plan (1997 Plan). In accordance with the
1992 Plan, options to purchase the Company common stock could have been granted
to officers and key employees of the Company at 90 percent of the fair market
value of the stock determined on the date of the grant. Under the 1997 Plan,
options to purchase the Company 's common stock could have been granted to
officers and key employees of the Company at the fair market value of the stock
determined on the date of the grant. Options from the 1992 Plan and the 1997
Plan were exercisable beginning two years from the date of the grant and expired
five years from the date of the grant. In addition, upon a change in control
event, which occurred with shareholder approval of the Company's acquisition by
SCANA, all outstanding options became exercisable on July 1, 1999.
No options were granted under the plans subsequent to fiscal year 1998. Options
exercised and canceled under both plans for the periods indicated were as
follows:
Options Weighted-Average
Outstanding Exercise Price
------------------------------------------------------------------------------
September 30, 1998 955,684 $18.46
Exercised (149,212) $14.66
Canceled (101,680) $20.54
---------------------------------------------------------
September 30, 1999 704,792 $18.97
Exercised (60,647) $12.86
---------------------------------------------------------
December 31,1999 644,145 $19.08
Exercised (644,145) $19.08
---------------------------------------------------------
December 31, 2000 and 2001 - -
=========================================================
At September 30 and December 31, 1999, all outstanding options were
exercisable at the weighted average prices indicated above. As of December 31,
1999, the 644,145 outstanding options had a weighted average remaining
contractual life of 2.6 years and exercise prices ranging from $12.86 to $21.25.
Employee Stock Purchase Plan
Under the 1992 Employee Stock Purchase Plan, as amended, the Company
was authorized to issue common stock to its full-time employees, nearly all of
whom were eligible to participate, at a purchase price equal to 90 percent of
such common stock's fair value. This plan was terminated effective June 30,
1999. In fiscal 1999 the Company issued 62,355 shares to employees.
For purposes of pro forma disclosure, the weighted average fair value
at grant date for employee stock options granted was estimated using the
Black-Scholes option pricing model with the following weighted average
assumptions:
1999
--------------------------------------------- ----------------------
Risk free interest rate 4.58%
Volatility factor 14.96%
Dividend yield 3.85%
Expected life 1 year
The weighted average fair value of each employee stock purchase plan
grant during fiscal 1999 was $6.52.
7. LONG-TERM DEBT
The annual amounts of long-term debt maturities for the years 2002
through 2006 are summarized as follows:
------------------- ----------------- ------------------ -----------------
Year Amount Year Amount
------------------- ----------------- ------------------ -----------------
(Millions of Dollars)
2002 $4.3 2005 $3.2
2003 7.5 2006 3.2
2004 7.5
------------------- ----------------- ------------------ -----------------
On February 16, 2001 the Company issued $150 million of medium-term
notes having an annual interest rate of 6.625 percent and maturing on February
15, 2011. The proceeds were used to reduce short-term debt and for general
corporate purposes.
Under the terms of the debt agreements, there are various provisions
relating to the maintenance of certain financial ratios and conditions, the most
significant of which could restrict payment of dividends. At December 31, 2001,
the Company is in compliance in all material respects with the requirements of
its debt agreements.
8. SHORT-TERM BORROWINGS
Millions of dollars 2001 2000
- ----------------------------------------------------------- ---------------
Authorized lines of credit $125.0 $125.0
Unused lines of credit $125.0 $125.0
Short-term borrowings outstanding:
Commercial paper (270 days or less) - $125.0
Weighted average interest rate n/a 6.69%
The Company pays fees to banks as compensation for its committed lines
of credit.
9. INCOME TAXES
Total income tax expense attributable to income (before cumulative effect
of accounting change) for 2001, 2000 and 1999 is as follows:
Three Months
Year Ended Ended Year Ended
December 31, December 31, September 30,
2001 2000 1999 1999
- ---------------------------------------------------- ----------------- ---------------- ----------------- ---------------
(Millions of Dollars)
Current taxes:
Federal $14.0 $18.6 $2.9 $9.0
State 3.0 3.9 0.6 2.1
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Total current taxes 17.0 22.5 3.5 11.1
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Deferred taxes, net:
Federal 1.2 1.5 0.6 5.4
State 0.3 0.3 0.1 1.2
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Total deferred taxes 1.5 1.8 0.7 6.6
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Investment tax credits:
Amortization of amounts deferred - Federal (0.3) (0.4) - (0.4)
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Total investment tax credits (0.3) (0.4) - (0.4)
- ---------------------------------------------------- ----------------- ---------------- ---------------- ----------------
Total income tax expense $18.2 $23.9 $4.2 $17.3
==================================================== ================= ================ ================ ================
The difference between actual income tax expense and the amount
calculated from the application of the statutory 35 percent Federal income tax
rate to pre-tax income (before cumulative effect of accounting change) is
reconciled as follows:
Three Months Twelve Months
Year Ended Ended Ended
December 31, December 31, September 30,
2001 2000 1999 1999
- ------------------------------------------------------------- ----------- ------------ --------------- ---------------
Income before cumulative effect of accounting change $14.8 $21.2 $5.1 $24.1
Total income tax expense:
Charged to operating expense 15.7 20.6 3.8 15.3
Charged to other income 3.3 0.4 2.0
2.5
- ------------------------------------------------------------- ----------- ------------ --------------- ---------------
Total pre-tax income $33.0 $45.1 $9.3 $41.4
============================================================= =========== ============ =============== ===============
============================================================= =========== ============ =============== ===============
Income taxes on above at statutory Federal income tax rate $11.6 $15.8 $3.3 $14.5
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 2.1 2.8 0.5 2.1
Non-deductible book amortization of acquisition 4.7 4.7 - -
adjustments
Amortization of Federal investment tax credits - (0.4)
(0.3) (0.4)
Other differences, net 0.1 1.0 0.4 1.1
- ------------------------------------------------------------- ----------- ------------ --------------- ---------------
- ------------------------------------------------------------- ----------- ------------ --------------- ---------------
Total income tax expense $18.2 $23.9 $4.2 $17.3
============================================================= =========== ============ =============== ===============
The tax effects of significant temporary differences comprising the Company's
net deferred tax liability of $85.8 million at December 31, 2001 and $80.7
million at December 31, 2000 are as follows:
- ---------------------------------------------------------------------------------- ---------------- ------------------
2001 2000
- ---------------------------------------------------------------------------------- ---------------- ------------------
(Millions of Dollars)
Deferred tax assets:
Unamortized investment tax credits $1.0 $1.0
Other 0.5 2.9
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax assets 1.5 3.9
- ---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 85.2 82.2
Other 2.1 2.4
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax liabilities 87.3 84.6
- ---------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability $85.8 $80.7
================================================================================== ================ ==================
10. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2001 and 2000 are as follows:
Millions of dollars 2001 2000
--------------------------------------------- ----------------------------- ------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
--------------------------------------------- -------------- -------------- --------------- --------------
Assets:
Cash and temporary cash investments $18 $18 $8 $8
Liabilities:
Short-term borrowings - - 125 125
Long-term debt 294 298 149 154
The following methods and assumptions were used to estimate the fair
value of the above classes of financial instruments:
o Cash and temporary cash investments are valued at their carrying amount.
o Fair values of long-term debt are based on quoted market prices
of the instruments or similar instruments. For debt instruments
for which there are no quoted market prices available, fair
values are based on net present value calculations. The carrying
values reflect the fair values of interest rate swaps based on
settlement values obtained from counterparties. Settlement of
long-term debt may not be possible or may not be considered
prudent.
o Short-term borrowings are valued at their carrying amount.
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. SFAS 133 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 fair value
of derivative instruments are either recognized in earnings or reported as other
comprehensive income, depending upon the intended use of the derivative and the
resulting designation. The impact on the Company of adopting SFAS 133 was not
material.
In December 2001 the Company entered into a two
interest rate swap agreements to pay variable rates and
receive fixed rate interest payments on a combined notional amount of $44.9
million. These swaps were designated as fair value hedges of the Company's $12.9
million, 10% senior debenture due 2004 and $32.0 million, 8.75% senior debenture
due 2012.
The fair value of these interest rate swaps is reflected within other
deferred debits on the balance sheet. The corresponding hedge debt is also
marked to market on the balance sheet. The receipts or payments related to the
interest rate swaps are credited or charged to interest expense as incurred.
11. COMMITMENTS AND CONTINGENCIES
A. The Company owns, or has owned, all or portions of seven sites in
North Carolina on which manufactured gas plants (MGPs) were formerly operated.
Intrusive investigation (including drilling, sampling and analysis) has begun at
two sites, and the remaining sites have been evaluated using historical records
and observations of current site conditions. These evaluations have revealed
that MGP residuals are present or suspected at several of the sites. The Company
estimates that the cost to remediate the sites would range between $11.3 million
and $21.9 million. The estimated cost range has not been discounted to present
value. The Company's associated actual costs for these sites will depend on a
number of factors, such as actual site conditions, third-party claims and
recoveries from other potentially responsible parties (PRPs). At December 31,
2001 the Company has recorded a liability and associated regulatory asset of
$9.1 million, which reflects the minimum amount of the range, net of shared cost
recovery expected from other PRPs and expenditures for work completed. Amounts
incurred to date are approximately $1.1 million. Management believes that all
costs incurred will be recoverable through gas rates.
B. The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates
will be resolved without material loss to the Company.
C. Purchase commitments under forward contracts for natural gas purchases
are $162 million and $69 million in 2002 and 2003, respectively.
12. RESTRUCTURING
During fiscal 1999, the Company recorded net restructuring charges of
$4.3 million. These charges consisted of severance benefits of $3.7 million, a
one-time payment to 152 employees of $1 million in connection with an automobile
fleet restructuring, a net curtailment loss on postretirement benefit
obligations of $.5 million (offset by pension gains of $1.8 million) and $.8
million of other restructuring charges.
13. SEGMENT OF BUSINESS INFORMATION
For the year ended December 31, 2001 Gas Distribution is the Company's
sole reportable segment. Subsidiaries whose operations comprised the Energy
Marketing segment were sold to an affiliate effective January 1, 2001 (see Note
4). Affiliate revenue is derived from transactions between reportable segments.
Prior to December 31, 1999 Sonat was an equity investment and not a segment of
business (see Note 4).
Gas distribution uses operating income to measure profitability. The
Company did not have deferred tax assets for any period reported. Interest
income was not significant. For 2000 adjustments to net income and income tax
expense include the cumulative effect of the accounting change described in Note
2.
Disclosure of Reportable Segments
Millions of dollars
- ------------------------------- ------------------- --------------- ------------------------- -------------------
Year Ended Gas All Adjustments/ Consolidated
December 31, 2001 Distribution Other Eliminations Total
- ------------------------------- ------------------- --------------- ------------------------- -------------------
External Revenue $453 - - $453
Intersegment Revenue - - - -
Deprec. & Amort. 43 - - 43
Operating Income 49 n/a - 49
Interest Expense 22 - - 22
Segment Assets 1,184 29 8 1,221
Expenditures for Assets 75 - - 75
- ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------
Year Ended Gas Energy All Adjustments/ Consolidated
December 31, 2000 Distribution Marketing Other Eliminations Total
- ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------
External Revenue $432 $141 - $(26) $547
Intersegment Revenue - 1 $30
(31) -
Deprec. & Amort. 42 - - - 42
Operating Income 54 n/a n/a 3
57
Interest Expense 20 - - - 20
Net Income n/a 2 5 21
28
Segment Assets 1,235 35 72 (89) 1,253
Expenditures for Assets 39 - - - 39
- ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------
Three Months Ended Gas Energy All Adjustments/ Consolidated
December 31, 1999 Distribution Marketing Other Eliminations Total
- ------------------------------- ------------------- ---------------- -------------- -------------------- ------------------
External Revenue $81 n/a - - $81
Intersegment Revenue - n/a $27 $(27) -
Deprec. & Amort. 7 n/a - - 7
Operating Income 13 n/a n/a - 13
Interest Expense 5 n/a - - 5
Net Income n/a n/a -
5 5
Segment Assets 678 $20 58 (58)
698
Expenditures for Assets 12 n/a - -
12
- ------------------------------- ------------------- -------------------- -------------------- -------------------
Fiscal Year Ended Gas All Adjustments/ Consolidated
September 30, 1999 Distribution Other Eliminations Total
- ------------------------------- ------------------- -------------------- -------------------- -------------------
External Revenue $298 $6 $(6) $298
Intersegment Revenue - 39 (39) -
Deprec. & Amort. 26 1 26
(1)
Operating Income 53 n/a - 53
Interest Expense 18 - - 18
Net Income n/a 2 22 24
Segment Assets 637 46 (34) 649
Expenditures for Assets 44 - - 44
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of dollars
- --------------------------------------------------------- ------------ ----------- ----------- ----------- -----------
2001 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- --------------------------------------------------------- ------------ ----------- ----------- ----------- -----------
Total operating revenues $228 $67 $47 $111 $453
Operating income (loss) 39 (2) (9) 21 49
Net income (loss) 20 (5) (10) 10 15
- ---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------
2000 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- ---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Total operating revenues $171 $80 $76 $220 $547
Operating income (loss) 37 (2) (7) 29 57
Cumulative effect of accounting change, net of taxes 7 - - - 7
Net income (loss) 26 (5) (8) 15 28
PART II, ITEM 9 AND PART III
SCANA CORPORATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE:
SCANA: None
SCE&G: None
PSNC: None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
SCANA:
The other information required by Item 10 is incorporated herein by
reference, to the captions "Election of Directors: Proposal 1 - Nominees For
Class III Directors", "Continuing Directors", and "Other Information - Section
16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy
statement for the 2002 annual meeting of shareholders which was filed with the
SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of
1934.
EXECUTIVE OFFICERS OF SCANA CORPORATION
The executive officers are elected at the annual organizational meeting
of the Board of Directors, held immediately after the annual meeting of
shareholders, and hold office until the next such organizational meeting, unless
a resignation is submitted, or unless the Board of Directors shall otherwise
determine. Positions held are for SCANA Corporation and all subsidiaries unless
otherwise indicated.
Name Age Positions Held During Past Five Years Dates
---- --- ------------------------------------- -----
W. B. Timmerman 55 Chairman of the Board, President and Chief Executive Officer *-present
H. T. Arthur 56 Senior Vice President, General Counsel and Assistant Secretary 1998-present
Vice President, General Counsel and Assistant Secretary *-1998
G. J. Bullwinkel 53 Senior Vice President, Governmental Affairs and
Economic Development 1999-present
President and Chief Operating Officer, SCI 1997-present
Senior Vice President - Retail Electric, SCE&G *-1999
S. A. Byrne 42 Senior Vice President-Nuclear Operations, SCE&G 2001-present
Vice President-Nuclear Operations, SCE&G 2000-2001
General Manager Nuclear Plant Operations, SCE&G *-2000
A. H. Gibbes 55 President and Chief Operating Officer, SCPC *-present
President and Treasurer, SCANA Development Corp. *-present
D. C. Harris 49 Senior Vice President of Human Resources 2000-present
Vice President Human Resources, Austin Quality Foods,
Inc., Cary, NC *-2000
N. O. Lorick 51 President and Chief Operating Officer, SCE&G 2000-present
Vice President - Fossil and Hydro Operations, SCE&G *-2000
K. B. Marsh 46 President and Chief Operating Officer, PSNC 2001-present
Senior Vice President and Chief Financial Officer 1998-present
Vice President - Finance, Chief Financial Officer *-1998
Controller *-2000
A. M. Milligan 42 Senior Vice President - Marketing 1998-present
President and Chief Operating Officer, SCANA Resources, Inc. 2001-present
President, SCANA Resources, Inc. 1999-2001
Director of Consumer Credit Marketing, Barnett Bank, N. A., FL *-1998
J. E. Addison 41 Vice President - Finance 2002-present
Vice President - SCANA Services, Inc. 2000-2002
Vice President and Controller, SCE&G *-2000
M. R. Cannon 51 Controller 2000-present
Treasurer, SCANA and all subsidiaries (excluding SCPC) *-2000
* Indicates position held at least since March 1, 1997.
SCE&G: DIRECTORS
The directors listed below were elected May 3, 2001 (except as otherwise
indicated) to hold office until the next annual meeting of SCE&G's shareholders
on May 2, 2002.
Name and Year First Age Principal Occupation; Directorships
Became Director
Bill L. Amick 58 For more than five years, Chairman of the Board and Chief Executive Officer of Amick Farms,
(1990) Inc., Amick Processing, Inc. and Amick Broilers, Inc., Batesburg, SC (vertically
integrated
broiler operation).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; Blue Cross and Blue
Shield of South Carolina, Columbia, SC.
James A. Bennett 41 Since May 2000, President and Chief Executive Officer of South Carolina Community Bank,
(1997) Columbia, SC.
From February 2000 to May 2000, Economic
Development Director, First Citizens
Bank, Columbia, SC.
From December 1998 to February 2000,
Senior Vice President and Director of
Professional Banking, First Citizens
Bank.
From December 1994 to December 1998,
Senior Vice President and Director of
Community Banking, First Citizens Bank.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
William B. Bookhart, Jr. 60 For more than five years, a partner in Bookhart Farms, Elloree, SC (general farming).
(1979)
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC.
William C. Burkhardt 64 Retired since May 2000.
(2000)
From 1980 until May 2000, President and
Chief Executive Officer of Austin Quality
Foods, Inc., Cary, NC (production and
distribution of baked snacks).
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; Capital Bank and
Industrial Microwave Systems, Raleigh, NC.
Hugh M. Chapman 68 Since June 30, 1997, retired from NationsBank South, Atlanta, GA (a division of
(1988) NationsBank Corporation, bank holding company).
For more than five years prior to June 30,
1997 Chairman of NationsBank South.
Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; West Point-Stevens,
West Point, GA; PrintPack, Inc., Atlanta, GA; The Williams Companies, Inc., Tulsa, OK.
Elaine T. Freeman 66 For more than five years, Executive Director of ETV Endowment of South Carolina, Inc.
(1992) (non-profit organization), Spartanburg, SC.
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; National Bank of
South Carolina (a member bank of Synovus
Financial Corporation), Columbia, SC.
Name and Year First Age Principal Occupation; Directorships
Became Director
Lawrence M. Gressette, Jr. 69 Since February 28, 1997, Chairman Emeritus, SCANA Corporation, Columbia, SC.
(1987)
For more than five years prior to
February 28, 1997, Chairman of the
Board and Chief Executive Officer,
SCANA Corporation.
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC.
D. Maybank Hagood 40 For more than five years, President and Chief Executive Officer of William M. Bird and
(1999) Company, Inc., Charleston, SC (wholesale distributor of floor covering materials).
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC.
W. Hayne Hipp 62 For more than five years, Chairman, and Chief Executive Officer, The Liberty
(1983) Corporation, Greenville, SC (broadcasting holding company).
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC; The Liberty
Corporation, Greenville, SC.
Lynne M. Miller 50 Since February 1998, Chief Executive Officer of
Environmental Strategies Corporation, (1997) Reston, VA
(environmental consulting and engineering firm).
For more than five years prior to
February 1998, President of
Environmental Strategies Corporation.
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC; Adams National
Bank, (a Subsidiary of Abigail Adams
National Bancorp, Inc.), Washington,
DC.
Maceo K. Sloan 52 For more than five years, Chairman, President and Chief Executive Officer of Sloan Financial
(1997) Group, Inc. (holding company) and Chairman and Chief Executive Officer of NCM Capital
Management Group, Inc. (investment management company), Durham, NC.
Director, SCANA Corporation, Columbia, SC; PSNC, Gastonia, NC; M&F Bankcorp, Inc., and
its subsidiary, Mechanics and Farmers Bank, Durham, NC; and
Trustee of Teachers Insurance Annuity Association - College Retirement Equity Fund (TIAA-
CREF).
Harold C. Stowe 55 Since March 1997, President and Chief Executive Officer of Canal Holdings, LLC and its
(1999) predecessor company, Conway, SC (forest products industry).
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC; Canal Holdings,
LLC, Conway, SC; Ruddick Corporation,
Charlotte, NC.
William B. Timmerman 55 Since March 1997, Chairman of the Board and Chief Executive Officer, SCANA
(1991) Corporation, Columbia, SC.
Since December 1995, President, SCANA Corporation.
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC; ITC^DeltaCom,
Inc., West Point, GA; The Liberty
Corporation, Greenville, SC.
G. Smedes York 61 For more than five years, President and Treasurer of York Properties, Inc., Raleigh, NC.
(2000) (full-service commercial and residential real estate company).
Director, SCANA Corporation, Columbia,
SC; PSNC, Gastonia, NC.
EXECUTIVE OFFICERS OF SCE&G
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
the Board of Directors shall otherwise determine, or unless a resignation is
submitted.
Positions Held During
Name Age Past Five Years Dates
W. B. Timmerman 55 Chairman of the Board and Chief Executive Officer *-present
H. T. Arthur 56 Senior Vice President, General Counsel and Assistant Secretary 1998-present
Vice President, General Counsel and Assistant Secretary *-1998
S. A. Byrne 42 Senior Vice President-Nuclear Operations 2001-present
Vice President-Nuclear Operations 2000-2001
General Manager Nuclear Plant Operations *-2000
N. O. Lorick 51 President and Chief Operating Officer 2000-present
Vice President - Fossil and Hydro Operations *-2000
K. B. Marsh 46 Senior Vice President - Finance and Chief Financial
Officer 1998-present
Vice President - Finance and Chief Financial Officer *-1998
Controller *-2000
M. R. Cannon 51 Controller 2000-present
Treasurer *-2000
*Indicates position held at least since March 1, 1997
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 executive officers. Based solely on a review of the copies of such
forms and amendments furnished to SCE&G and written representations from the
executive officers and directors, SCE&G believes that during 2001 all Section
16(a) filing requirements applicable to its executive officers, directors and
greater than 10 percent beneficial owners were complied with.
ITEM 11. EXECUTIVE COMPENSATION
SCANA: The information called for by Item 11, Executive Compensation, is
incorporated herein by reference to the captions "Director Compensation,"
"Compensation Committee Interlocks and Insider Participation," and "Executive
Compensation" in SCANA's definitive proxy statement for the 2002 annual meeting
of shareholders.
SCE&G: The information called for by Item 11, Executive Compensation, is as follows:
Summary Compensation Table
- ------------------------------------ ------ ---------------------------------------------- ----------------------------------------
Annual Compensation Long-Term Compensation
-------------------------------------------- ------------------------------------------
Awards Payouts
-------------- -----------
Securities
Other Underlying All
Annual Option/ LTIP Other
Year Salary Bonus(1) Compensation(2) SARS Payouts(3) Compensation(4)
Name and Principal Position ($) ($) ($) (#) ($) ($)
- ------------------------------------ ------ ------------- ----------- ------------------ -------------- ----------- ---------------
W. B. Timmerman 2001 660,238(5) 17,611 129,781 60,884
- -
Chairman, President and Chief 2000 524,261 354,486 17,888 35,620 50,230
-
Executive Officer - SCANA 1999 490,313 312,900 17,212 - 298,813 29,419
N. O. Lorick 2001 385,252 18,701 36,711 30,611
-
President and Chief Operating 2000 167,778 124,921 7,313 2,332 12,728
-
Officer - SCE&G 1999 157,417 44,356 7,313 - 38,754 9,445
K. B. Marsh 2001 334,234 10,554 36,711 29,097
- -
Senior Vice President 2000 276,172 150,720 10,613 11,627 24,254
-
and Chief Financial Officer - 1999 241,354 128,058 10,337 - 81,555 14,481
SCANA
H. T. Arthur 2001 270,963 16,119 19,142 23,487
- -
Senior Vice President and 2000 234,812 120,480 16,119 8,796 19,718
-
General Counsel 1999 219,806 93,825 15,939 - 65,843 13,188
S. A. Byrne 2001 244,232 9,465 19,142 22,064
- -
Senior Vice President-Nuclear 2000 183,555 123,492 8,310 8,796 12,962
-
Operations 1999 137,321 32,483 3,600 - 8,239
-
- ------------------------------------ ------ ------------- ----------- ------------------ -------------- ----------- ---------------
(1) Payments under the Annual Incentive Plan.
(2) For 2001, other annual compensation consists of automobile allowance,
life insurance premiums on policies owned by named executive officers and
payments to cover taxes on benefits of $9,000, $7,435 and $1,176 for Mr.
Timmerman; $10,250, $7,959 and $492 for Mr. Lorick; $9,000, $1,183 and
$371 for Mr. Marsh; $9000, $6,830 and $289 for Mr. Arthur and $9,000,
$180 and $285 for Mr. Byrne.
(3) Payments under the Long-term Equity Compensation Plan.
(4) All other compensation for all executive officers consists solely of Company
matching contributions to defined contribution plans. (5) Reflects actual salary
paid in 2001. Base salary of $676,300, became effective on February 3, 2001.
Options Grants and Related Information
Options/SAR Grants in Last Fiscal Year
Potential
Realizable Value at
Assumed Annual
Rates of Stock Price
Appreciation
Individual Grants for Option Term
- ---------------------------------------------------------------------------------- ----------------
(a) (b) (c) (d) (e) (f) (g)
Number of % of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise or
SARs Employees in Base Price Expiration
Name Granted (#) Fiscal Year ($/Sh) Date 5% ($) 10%($)
- ------------------------------- ----------------- --------------- ---------------- -------------- --------------
W. B. Timmerman 129,781 18.12 27.45 2-22-11 2,240,021 5,677,919
N. O. Lorick 36,711 5.12 27.45 2-22-11 633,632 1,606,106
K. B. Marsh 36,711 5.12 27.45 2-22-11 633,632 1,606,106
H. T. Arthur 19,142 2.67 27.45 2-22-11 330,451 837,429
S. A. Byrne 19,142 2.67 27.45 2-22-11 330,451 837,429
All the above options vest 33 1/3 percent on each of the first, second and third
anniversaries of the date of the grant, February 22, 2001.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR
Values
(a) (d) (e)
Number of
Securities
Underlying Value of Unexercised
Unexercised In-the-Money Options/
Option/SARs SARs at
At FY-End (#) FY-End ($) (1)
Exercisable/ Exercisable/
Name Unexercisable Unexercisable
- -------------------------------------------------------------------------------
W. B. Timmerman 11,873/153,528 27,664/104,648
N. O. Lorick 777/38,266 1,810/17,573
K. B. Marsh 3,875/44,463 9,029/32,012
H. T. Arthur 2,932/25,006 6,832/20,937
S. A. Byrne 2,932/25,006 6,832/20,937
(1)Based on the closing price of $27.83 per share on December 31, 2001, the last
trading date of the fiscal year.
The following table lists the performance share awards made in 2001 (for
potential payment in 2004) under the Long-Term Equity Compensation Plan and
estimated future payouts under that plan at threshold, target and maximum levels
for each of the executive officers included in the Summary Compensation Table.
LONG-TERM INCENTIVE PLANS
AWARDS IN LAST FISCAL YEAR
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
--------------------------------------
Units or Period Until
Other Maturation Threshold Target Maximum
Name Rights (#) or Payout (#) (#) (#)
- ----------------------------------------------------------------------------
W. B. Timmerman 20,132 2001-2003 8,053 20,132 30,198
N. O. Lorick 5,695 2001-2003 2,278 5,695 8,543
K. B. Marsh 5,695 2001-2003 2,278 5,695 8,543
H. T. Arthur 2,969 2001-2003 1,188 2,969 4,454
S. A. Byrne 2,969 2001-2003 1,188 2,969 4,454
Payouts occur when SCANA's Total Shareholder Return is in the top
two-thirds of the Long-Term Equity Compensation Plan peer group, and will vary
based on SCANA's ranking against the peer group. Executives earn threshold
payouts at the 33rd percentile of three-year performance. Target payouts will be
made at the 50th percentile of three-year performance. Maximum payouts will be
made when performance is at or above the 75th percentile of the peer group.
Payments will be made on a sliding scale for performance between threshold and
target and target and maximum. No payouts will be earned if performance is at
less than the 33rd percentile. 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.
DEFINED BENEFIT PLANS
SCANA has a tax qualified defined benefit retirement plan. The plan has
a mandatory cash balance benefit formula (the "Cash Balance Formula") for
employees hired on or after January 1, 2000. Effective July 1, 2000, SCANA
employees hired prior to January 1, 2000 were given the choice of remaining
under the Retirement Plan's final average pay benefit formula or switching to
the cash balance benefit option. All the executive officers named in the Summary
Compensation Table elected to participate under the cash balance option of the
plan.
The Cash Balance Formula benefit is expressed in the form of a
hypothetical account balance. Employees electing to participate under the cash
balance option had an opening account balance established for them. The opening
account balance was equal to the present value of the participant's June 30,
2000 accrued benefit under the final average pay formula. Participants who had
20 years of vesting service or who had 10 years of vesting service and whose age
plus service equaled at least 60 were given transition credits. For these
participants, the beginning account balance was determined so that projected
benefits under the cash balance option approximated projected benefits under the
final average pay formula at the earliest date at which unreduced benefits are
payable under the plan.
Account balances are increased monthly by interest and compensation
credits. The interest rate used for accumulating account balances changes
annually and is equal to the average rate for 30-year Treasuries for December of
the previous calendar year. Compensation credits equal 5 percent of compensation
under the Social Security Wage Base and 10 percent of compensation in excess of
the Social Security Wage Base.
In addition to its Retirement Plan for all employees, SCANA has
Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees
including officers. A SERP 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 estimated annual retirement benefits payable as life annuities at
age 65 under the plans, based on projected compensation (assuming increases of 4
percent per year), to the executive officers named in the Summary Compensation
Table are as follows: Mr. Timmerman - $427,476; Mr. Lorick - $282,696; Mr. Marsh
- - $311,556; Mr. Arthur - $111,024 and Mr. Byrne - $238,440.
TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS
SCANA maintains an Executive Benefit Plan Trust. The purpose of the
trust is to help retain and attract quality leadership in key SCANA positions in
the current transitional environment of the utilities industry. The trust holds
SCANA contributions (if made) which may be used to pay the deferred and other
compensation benefits of certain directors, executives and other key employees
of SCANA in the event of a Change in Control (as defined in the trust). The
current executive officers included in the Summary Compensation Table
participate in all the plans listed below which are covered by the trust.
(1) SCANA Corporation Executive Deferred Compensation Plan (2) SCANA
Corporation Supplemental Executive Retirement Plan (3) SCANA Corporation
Long-Term Equity Compensation Plan (4) SCANA Corporation Annual Incentive Plan
(5) SCANA Corporation Key Executive Severance Benefits Plan (6) SCANA
Corporation Supplementary Key Executive Severance Benefits Plan
The Key Executive Severance Benefits Plan and each of the plans listed
under (1) through (4) provide for payment of benefits in a lump sum to the
eligible participants immediately upon a Change in Control, unless the Key
Executive Severance Benefits Plan is terminated prior to the Change in Control.
In contrast, the Supplementary Key Executive Severance Benefits Plan is
operative for a period of 24 months following a Change in Control where the Key
Executive Severance Benefits Plan is inoperative because it was terminated
before the Change in Control. The Supplementary Key Executive Severance Benefits
Plan provides benefits in lieu of those otherwise provided under plans (1)
through (4) if: (i) the participant is involuntarily terminated from employment
without "Just Cause," or (ii) the participant voluntarily terminates employment
for "Good Reason" (as these terms are defined in the Supplementary Key Executive
Severance Benefits Plan).
Benefit distributions relative to a Change in Control, as to which
either the Key Executive Severance Benefits Plan or the Supplementary Key
Executive Severance Benefits Plan is operative, include an amount equal to
estimated federal, state and local income taxes and any estimated applicable
excise taxes owned by the plan participants on those benefits.
The benefit distributions under the Key Executive Severance Benefits
Plan would include the following three benefits:
o An amount equal to three times the sum of: (i) the participant's annual
base salary in effect as of the Change in Control and (ii) the officer's
target annual incentive award in effect as of the Change in Control under
the Annual Incentive Plan.
o 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 the participant had continued to be a SCANA
employee.
o An amount equal to the participant's Supplemental Executive Retirement
Plan benefit accrued to the date of the Change in Control, increased by
the present value of projected benefits that would otherwise accrue under
the plan (based on the plan's actuarial assumptions) assuming that the
participant remained employed until reaching age 65 and offset by the
value of the participant's Retirement Plan benefit.
Additional benefits payable upon a Change in Control where the Key
Executive Severance Benefits Plan is operable are:
o A benefit distribution of all amounts credited to the participant's
Executive Deferred Compensation Plan account as of the date of the Change
in Control.
o A benefit distribution under the Long-Term Equity Compensation Plan equal
to 100 percent of the targeted performance share awards for all performance
periods not completed as of the date of the Change in Control, if any.
o Under the Long-Term Equity Compensation Plan, all nonqualified stock
options awarded would become immediately exercisable and remain exercisable
throughout their term.
o A benefit distribution under the Annual Incentive Plan equal to 100 percent
of the target award in effect as of the date of the Change in Control.
The benefits and their respective amounts, when the Supplementary Key
Executive Severance Benefits Plan is operable, would be the same except that the
benefits payable with respect to the Executive Deferred Compensation Plan would
be increased by the prime rate published in the Wall Street Journal most nearly
preceding the date of the Change in Control plus three percent (3 percent)
calculated until the end of the month preceding the month in which the benefits
are distributed.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 2001, decisions on various elements of executive compensation
were made by the Management Development and Corporate Performance Committee and
the Long-Term Equity Compensation Plan Committee. No officer, employee or former
officer of SCANA or any of its subsidiaries served as a member of the Management
Development and Corporate Performance Committee or the Long-Term Equity
Compensation Plan Committee except Mr. Timmerman, who served as an ex-officio,
non-voting member of the Management Development and Corporate Performance
Committee.
The names of the persons who serve on the Management Development and
Corporate Performance Committee and the Long-Term Equity Compensation Plan
Committee can be found at Item 12, Security Ownership of Certain Beneficial
Owners and Management. Although Mr. Timmerman served as a member of the
Management Development and Corporate Performance Committee, he did not
participate in any of its decisions concerning executive officer compensation.
Director Compensation
Board Fees
Officers of SCANA who are also directors do not receive additional
compensation for their service as directors. Since July 1, 2000, compensation
for non-employee directors has included the following:
o an annual retainer of $30,000 (60 percent of the annual retainer fee is paid
in shares of SCANA Common Stock); o $3,500 for each board meeting attended; o
$3,000 for attendance at a committee meeting held on a day other than a regular
meeting of the Board; o $250 for participation in a telephone conference
meeting; o $2,000 for attendance at an all-day conference; and o reimbursement
for expenses incurred in connection with all of the above.
Director Compensation and Deferral Plans
Since January 1, 2001, non-employee director compensation deferrals
have been governed by the SCANA Corporation 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.
Under the new plan, a director may elect to defer the 60 percent of the
annual retainer fee required to be paid in SCANA Common Stock, in a hypothetical
investment in SCANA Common Stock, with distribution from the plan to be
ultimately payable in actual shares of SCANA Common Stock. A director may also
elect to defer the 40 percent of the annual retainer fee not required to be paid
in shares of SCANA Common Stock and up to 100 percent of meeting attendance and
conference fees with distribution from the plan to be ultimately payable in
either SCANA Common Stock or cash. Amounts payable in SCANA Common Stock accrue
earnings during the deferral period at SCANA's dividend rate, which amount may
be elected to be paid in cash when accrued or retained to invest in hypothetical
shares of SCANA Common Stock. Amounts payable in cash accrue interest earnings
until paid.
During 2001, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and
York and Ms. Miller elected to defer 100 percent of their compensation and
earnings under the Director Compensation and Deferral Plan so as to acquire
hypothetical shares of SCANA Common Stock. In addition, Mr. Hagood elected to
defer 60 percent of his annual retainer and earnings under the plan to acquire
hypothetical shares of SCANA Common Stock.
Endowment Plan
Upon election to a second term, a director becomes eligible to
participate in the SCANA Director Endowment Plan, which provides for SCANA to
make a tax deductible, charitable contribution totaling $500,000 to institutions
of higher education designated by the director. The plan is intended to
reinforce SCANA's commitment to quality higher education and to enhance its
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. The
plan is funded in part through insurance on the lives of the directors.
Designated in-state institutions of higher education must be approved by the
Chief Executive Officer of SCANA. Any out-of-state designation must be approved
by the Management Development and Corporate Performance Committee. The
designated institutions are reviewed on an annual basis by the Chief Executive
Officer to assure compliance with the intent of the program.
Other As a Company retiree, Mr. Gressette receives monthly retirement
benefits of $39,571.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SCANA: The information called for by Item 12, Security Ownership of Certain
Beneficial Owners and Management is incorporated herein by reference to the
caption "Share Ownership of Directors, Nominees and Executive Officers" and
"Five Percent Owner of SCANA Common Stock" in SCANA's definitive proxy statement
for the 2002 annual meeting of shareholders.
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 28, 2002 by each director, each nominee and each executive officer
named in the Summary Compensation table on page 152.
SECURITY OWNERSHIP OF MANAGEMENT
Amount and Nature Amount and Nature
of Beneficial Ownership of of Beneficial Ownership of
Name SCANA Common Stock of SCANA Common
*(1)(2)(3)(4)(5) Name Stock *(1) (2) (3)(4) (5)
- ----- -------------------------------- ---------------------------------
B. L. Amick 10,896 D. M. Hagood 822
H. T. Arthur 26,292 W. H. Hipp 4,897
J. A. Bennett 2,286 N. O. Lorick 29,604
W. B. Bookhart, Jr. 21,725 K. B. Marsh 35,778
W. C. Burkhardt 11,626 L. M. Miller 3,417
S. A. Byrne 17,163 M. K. Sloan 4,132
H. M. Chapman 8,212 H. C. Stowe 4,127
E. T. Freeman 6,184 W. B. Timmerman 122,257
L. M. Gressette, Jr. 63,858 G. S. York 11,225
*Each of the directors, nominees and named executive officers owns less than 1
percent of the shares outstanding.
All directors and executive officers as a group (21 persons) TOTAL 415,642.
TOTAL PERCENT OF CLASS, outstanding and entitled to vote at the Annual Meeting
of Shareholders 0.4 percent.
1) Includes shares owned by close relatives, the beneficial ownership of which
is disclaimed by the director, nominee or named executive officers, as
follows: Mr. Amick-480; Mr. Bookhart-6,064; Mr. Gressette-1,060; and by all
directors, nominees and executive officers 7,604 in total.
(2) Includes shares purchased through February 28, 2002, by the Trustee under
SCANA's Stock Purchase Savings Plan.
(3) Hypothetical shares acquired under the SCANA Director Compensation and
Deferral Plan are not included in the above table. As of February 28, 2002,
each of the following directors had acquired under the plan, the number of
hypothetical shares following his/her name: Messrs. Amick-3,280,
Bennett-3,945, Burkhardt-3,902, Hagood-1,359, Hipp-3,635, Sloan-3,485,
Stowe-3,245 and York-3,645 and Ms. Miller-3,822.
(4) Includes shares subject to currently exercisable options and options that
will become exercisable within 60 days in the following amounts: Mr.
Timmerman-67,007; Mr. Lorick-13,792; Mr. Marsh-19,988; Mr. Byrne-12,245;
Mr. Arthur-12,245.
(5)Hypothetical shares acquired under the SCANA Executive Deferred Compensation
Plan are not included in the above table. As of February 28, 2002, each of
the following officers had acquired under the plan, the number of
hypothetical shares following his/her name: Messrs. Timmerman-15,402;
Lorick-1,638; Marsh-3,410; Mr. Byrne-1,031; Mr. Arthur-2,241.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SCANA: The information called for by Item 13, Certain Relationships and Related
Transactions is incorporated herein by reference to the captions "Compensation
Committee Interlocks and Insider Participation" and "Related Transactions" in
SCANA's definitive proxy statement for the 2001 annual meeting of shareholders.
Notwithstanding anything to the contrary set forth in any of the
Company's previous filings under the Securities Act of 1933, as amended, or the
Securities Exchange Act of 1934, as amended, that might incorporate by reference
future filings, including this Annual Report on Form 10-K, in whole or in part,
the "Report on Executive Compensation", the "Performance Graph" and the "Audit
Committee Report" included in SCANA's definitive proxy statement for the 2002
annual meeting of shareholders shall not be incorporated by reference into any
such filings.
SCE&G: For information regarding certain relationships and related transactions,
see Item 11, Executive Compensation under the heading Compensation Committee
Interlocks and Insider Participation and the following:
During 2001, SCANA paid $120,983 (including the value of non-utility in
kind services provided by SCANA) to subsidiaries of The Liberty Corporation for
advertising expenses. Mr. Hipp is Chairman and Chief Executive Officer and a
director of The Liberty Corporation. It is anticipated that similar transactions
will occur in the future.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form
10-K:
(1) Financial Statements and Schedules:
The Independent Auditor's Reports on the financial
statements for SCANA, SCE&G and PSNC are listed under Item
8 herein.
The financial statements and supplementary financial data
filed as part of this report for SCANA, SCE&G and PSNC are
listed under Item 8 herein.
The Financial Statement Schedules filed as part of this
report for SCANA, SCE&G and PSNC are listed beginning on
page 159.
(2) Exhibits
Exhibits required to be filed 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 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 Commission when the information becomes
available.
As permitted under Item 601(b)(4)(iii), instruments defining
the rights of holders of long-term debt of less than 10
percent of the total consolidated assets of SCANA, for
itself and its subsidiaries, of SCE&G, for itself and its
subsidiaries, and of PSNC, for itself and its subsidiaries,
have been omitted and SCANA, SCE&G and PSNC agree to furnish
a copy of such instruments to the Commission upon request.
(b) Reports on Form 8-K during the fourth quarter of 2001 for SCANA, SCE&G and
PSNC:
None
SCANA:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2001, 2000 and 1999.
Additions
Charged to
Beginning Charged to Other Deductions Ending
Description Balance Income Accounts from Reserves Balance
- ------------------------------------------ ---------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2001 30,533,701 10,452,458 - 3,988,732 36,997,427
2000 7,302,273 25,574,187 - 2,342,759 30,533,701
1999 1,965,732 7,604,493 - 2,267,952 7,302,273
Reserve for investment impairment
2001 4,928,768 - 4,928,768
- -
2000 4,133,768 1,000,000 - 205,000 4,928,768
1999 10,292,611 - 6,158,843 4,133,768
-
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2001 7,349,339 264,849 - 1,762,900 5,851,288
2000 5,221,544 2,461,339 - 333,544 7,349,339
1999 4,287,986 1,352,448 - 418,890 5,221,544
Provision for decontamination and
decommissioning
2001 6,355,795 503,330 - 6,859,125
-
2000 6,487,365 - - 131,570 6,355,795
1999 6,256,249 231,116 - 6,487,365
-
Provision for environmental
remediation and settlement
2001 2,814,569 - - 420,382 2,394,187
2000 3,223,821 - - 409,252 2,814,569
1999 3,619,572 - - 395,751 3,223,821
SCE&G:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2001, 2000 and 1999.
Additions
Charged to
Beginning Charged to Other Deductions Ending
Description Balance Income Accounts From Reserves Balance
- --------------------------------------- ---------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2001 577,000 3,273,754 - 3,030,754 820,000
2000 537,000 2,381,626 - 2,341,626 577,000
1999 611,001 2,048,370 - 2,122,371 537,000
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2001 4,575,192 - - 1,154,138 3,421,054
2000 3,972,816 819,431 - 217,055 4,575,192
1999 4,176,794 104,000 - 307,978 3,972,816
Provision for decontamination and
decommissioning
2001 2,814,569 - - 420,382 2,394,187
2000 3,223,821 - - 409,252 2,814,569
1999 3,619,572 - - 395,751 3,223,821
PSNC:
Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31,
2001 and 2000, the Three Months Ended December 31, 1999 and the Fiscal Year
Ended September 30, 1999.
Additions
Beginning Charged to Charged to Deductions Ending
Description Balance Income Other Accounts from Reserves Balance
- ---------------------------------- --------------------- ---------------- ---------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2001 2,402,696 4,158,568 - 1,444,719
5,116,.545(a)
2000 2,702,014 2,417,566 - 2,716,884 2,402,696
Three Months 1999 1,737,815 470,895 - (199,069)
2,702,014(b)
Fiscal Year 1999 2,086,128 725,094 - 1,073,407 1,737,815
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2001 1,626,258 723,628 - 1,148,761 1,201,125
2000 2,197,615 494,629 - 1,065,986 1,626,258
Three Months 1999 1,930,377 442,000 - 174,762 2,197,615
Fiscal Year 1999 1,207,278 1,802,544 - 1,079,445 1,930,377
Provision for post-retirement &
post-employment
2001 398,000 - 398,000 -
-
2000 6,658,753 1,227,823 - 7,488,576 398,000
Three Months 1999 6,466,563 298,857 - 106,667 6,658,753
Fiscal Year 1999 5,165,324 1,676,767 - 375,528 6,466,563
(a)Includes $309,645 uncollectible reserve balance for SCANA Public Service
Company LLC which was sold to SCANA Energy Marketing effective January 1, 2001.
(b)Ending balance for December 31, 1999 includes $294,235 uncollectible reserve
balance for SCANA Public Service Company LLC (formerly Sonat Public Service)
purchased December 31, 1999.
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 thereof.
SCANA CORPORATION
s/W. B. Timmerman
BY: W. B. Timmerman, Chairman of the Board,
President, Chief Executive Officer and Director
DATE: March 27, 2002
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.
s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
s/K. B. Marsh
K. B. Marsh, Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
s/ M. R. Cannon
M. R. Cannon,
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr. L. M. Miller
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr.
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 27, 2002
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 thereof.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY: s/N. O. Lorick
N. O. Lorick, President and Chief
Operating Officer
DATE: March 27, 2002
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.
s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
s/K. B. Marsh
K. B. Marsh, Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
s/ M. R. Cannon
M. R. Cannon,
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr. L. M. Miller
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr.
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 27, 2002
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 thereof.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
BY: s/Kevin B. Marsh.
Kevin B. Marsh, President and Chief Operating Officer
DATE: March 27, 2002
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.
s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
s/K. B. Marsh
K. B. Marsh, Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
s/ M. R. Cannon
M. R. Cannon,
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr. L. M. Miller
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr.
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 27, 2002
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
2.01 X X Agreement and Plan of Merger, dated as of
February 16, 1999 as amended and
restated as of May 10, 1999, by and among
Public Service Company of North
Carolina, Incorporated, SCANA Corporation,
New Sub I, Inc. and New Sub II, Inc.
(Filed as Exhibit 2.1 to Registration
Statement No. 333-78227 on Form S-4 and
incorporated by reference herein)
3.01 X Restated Articles of Incorporation of
SCANA 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 of SCANA, 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
SCE&G, 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 of SCE&G, dated May
22, 2001 (Filed as Exhibit 3.02 to
Registration Statement No. 333-65460 and
incorporated by reference herein)
3.05 X Articles of Correction of SCE&G, dated
June 1, 2001 (Filed as Exhibit 3.03 to
Registration Statement No. 333-65460 and
incorporated by reference herein)
3.06 X Articles of Amendment of SCE&G, dated June
14, 2001 (Filed as Exhibit 3.04 to
Registration Statement No. 333-65460 and
incorporated by reference herein)
3.07 X Articles of Amendment of SCE&G, dated
August 30, 2001 (Filed as Exhibit
3.07 to Form 10-Q for the quarter ended
September 30, 2001 and incorporated by
reference herein)
3.08 X Articles of Incorporation of PSNC (formerly
New Sub II, Inc.) dated February 12,
1999 (Filed as Exhibit 3.01 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
3.09 X Articles of Amendment of PSNC (formerly
New Sub II, Inc.) as adopted on February
10, 2000 (Filed as Exhibit 3.02 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
3.10 X Articles of Correction of PSNC dated
February 11, 2000 (Filed as Exhibit 3.03 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
3.11 X Articles of Amendment of SCE&G, dated
March 13, 2002 (Filed herewith)
3.12 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)
3.13 X By-Laws of SCE&G as amended and adopted on
February 22, 2001 (Filed as Exhibit
3.05 to Registration Statement No. 333-
65460 and incorporated by reference
herein)
3.14 X By-Laws of PSNC (formerly New Sub II, Inc.)
as revised and amended on February
22, 2001 (Filed as Exhibit 3.01 to
Registration Statement No. 333-68516 and
incorporated by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
4.01 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)
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)
4.03 X X Indenture dated as of January 1, 1945, between the
South Carolina Power Company and Central Hanover
Bank and Trust Company, as Trustee, as
supplemented by three Supplemental Indentures
dated respectively as of May 1, 1946, May 1, 1947
and July 1, 1949 (Filed as Exhibit 2-B to
Registration Statement No. 2-26459 and
incorporated by reference herein)
4.04 X X Fourth Supplemental Indenture dated as of April
1, 1950, to Indenture referred to in Exhibit 4.03,
pursuant to which SCE&G assumed said Indenture
(Exhibit 2-C to Registration Statement No. 2-26459
and incorporated by reference herein)
4.05 X X Fifth through Fifty-third Supplemental Indenture
referred to in Exhibit 4.03 dated as of the dates
indicated below and filed as exhibits to the
Registration Statements whose file numbers are set
forth below and are incorporated by reference
herein
- --------
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
- --------
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
- --------
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
- --------
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
- --------
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
- --------
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
- --------
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
- --------
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
- --------
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
- --------
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
- --------
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
- --------
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
- --------
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
- --------
December 1, 1969 Exhibit 4-O to Registration No. 2-35388
- --------
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
- --------
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
- --------
January 1, 1972 Exhibit 2-B to Registration No. 33-38580
- --------
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
- --------
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
- --------
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
- --------
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
- --------
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
- --------
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
- --------
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
- --------
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
- --------
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
- --------
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
- --------
June 1, 1979 Exhibit 2-A-3 to Registration No. 33-38580
- --------
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
- --------
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
- --------
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
- --------
April 1, 1981 Exhibit 4-D to Registration No. 33-38580
- --------
June 1, 1981 Exhibit 4-D to Registration No. 33-49421
- --------
March 1, 1982 Exhibit 4-D to Registration No. 2-73321
- --------
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
- --------
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
- --------
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
- --------
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
- --------
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
- --------
February 1, 1987 Exhibit 4-D to Registration No. 33-49421
- --------
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
- --------
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
- --------
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
- --------
February 1, 1991 Exhibit 4-D to Registration No. 33-49421
- --------
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
- --------
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
- --------
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
- --------
July 1, 1993 Exhibit 4-D to Registration No. 33-49421
- --------
May 1, 1999 Exhibit 4.04 to Registration No. 333-86387
- --------
- --------
4.06 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)
- --------
4.07 X X First Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated as of
June 1, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-49421 and
incorporated by reference herein)
- --------
4.08 X X Second Supplemental Indenture to Indenture
referred to in Exhibit 4.06 dated as of
June 15, 1993 (Filed as Exhibit 4-G to
Registration Statement No. 33-57955 and
incorporated by reference herein)
- --------
4.09 X X Trust Agreement for SCE&G Trust I (Filed as
Exhibit 4.03 to Registration Statement
No. 333-49960 and incorporated by reference
herein)
- --------
4.10 X X Certificate of Trust of SCE&G Trust I (Filed a
Exhibit 4.04 to Registration Statement No.
333-49960 and incorporated by reference herein)
- --------
4.11 X X Junior Subordinated Indenture for SCE&G Trust I
(Filed as Exhibit 4.05 to Registration
Statement No. 333-49960 and incorporated by
reference herein)
- --------
4.12 X X Guarantee Agreement for SCE&G Trust I (Filed as
Exhibit 4.06 to Registration Statement No.
333-49960 and incorporated by reference herein)
- --------
4.13 X X Amended and Restated Trust Agreement for SCE&G
Trust I (Filed as Exhibit 4.07 toRegistration
Statement No. 333-49960 and incorporated by
reference herein)
- --------
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
4.14 X X Indenture dated as of January 1, 1996 between
PSNC and First Union National Bank of
North Carolina, as Trustee (Filed as Exhibit
4.08 to Registration Statement No.
333-45206 and incorporated by reference herein)
- --------
4.15 X X First Supplemental Indenture dated as of
January 1, 1996, between PSNC and First Union
National Bank of North Carolina, as Trustee
(Filed as Exhibit 4.09 to Registration
Statement No. 333-45206 and incorporated by
reference herein)
- --------
4.26 X X Second Supplemental Indenture dated as of
December 15, 1996 between PSNC and First
Union National Bank of North Carolina, as
Trustee (Filed as Exhibit 4.10 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
- --------
4.27 X X Third Supplemental Indenture dated as of
February 10, 2000 between PSNC and First
Union National Bank of North Carolina, as
Trustee (Filed as Exhibit 4.11 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
4.28 X X Fourth Supplemental Indenture dated as of
February 12, 2001 between PSNC and First
Union National Bank of North Carolina, as
Trustee (Filed as Exhibit 4.05 to
Registration Statement No. 333-68516 and
incorporated by reference herein)
- --------
4.29 X PSNC $150 million medium-term note issued
February 16, 2001 (Filed as Exhibit 4.06 to
Registration Statement No. 333-68516 and
incorporated by reference herein)
- --------
10.01 X SCANA Executive Deferral Compensation Plan as
amended July 1, 2001 (Filed as Exhibit
10.01 to Form 10-Q for the quarter ended
September 30, 2001 and incorporated by
reference herein)
- --------
10.02 X SCANA Supplementary Executive Retirement Plan
as amended July 1, 2001 (Filed as Exhibit 10.02
to Form 10-Q for the quarter ended September
30, 2001 and incorporated by reference herein)
- --------
10.03 X SCANA Key Executive Severance Benefits Plan as
amended July 1, 2001 (Filed as Exhibit
10.03 to Form 10-Q for the quarter ended
September 30, 2001 and incorporated by
reference herein)
- --------
10.04 X SCANA Supplementary Key Severance Benefits Plan
as amended July 1, 2001 (Filed as Exhibit 10.03a
to Form 10-Q for the quarter ended September 30,
2001 and incorporated by reference herein)
- --------
10.05 X SCANA Performance Share Plan as amended and
restated effective January 1, 1998 (Filed
as Exhibit 10 (e) to Registration Statement No.
333-86803 and incorporated by
reference herein)
- --------
10.06 X SCANA Long-Term Equity Compensation Plan dated
January 2000 filed as Exhibit 4.04 to
Registration Statement No. 333-37398 and
incorporated by reference herein)
- --------
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
- --------
10.07 X Description of SCANA Whole Life Option
(Filed as Exhibit 10-F to Form 10-K for the
year ended December 31, 1991, under cover
of Form SE, File No. 1-8809 and
incorporated by reference herein)
10.08 X Description of SCANA Corporation Executive
Annual Incentive Plan (Filed as Exhibit
10-G to Form 10-K for the year ended
December 31, 1991, under cover of Form SE,
File No. 1-8809 and incorporated by
reference herein)
10.09 X SCANA Corporation Director Compensation and
Deferral Plan effective January 1, 2001
(Filed as Exhibit 10.05 to Registration
Statement No. 333-49960 and incorporated by
reference herein)
10.10 X Operating Agreement of Pine Needle LNG
Company, LLC dated August 8, 1995 (Filed
as Exhibit 10.01 to Registration Statement
No. 333-45206 and incorporated by reference
herein)
10.11 X Amendment to Operating Agreement of Pine
Needle LNG Company, LLC dated October 1,
1995 (Filed as Exhibit 10.02 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
10.12 X Amended Operating Agreement of Cardinal
Extension Company, LLC dated December 19,
1996 (Filed as Exhibit 10.03 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
10.13 X Amended Construction, Operation and
Maintenance Agreement by and between
Cardinal Operating Company and Cardinal
Extension Company, LLC dated December 19,
1996 (Filed as Exhibit 10.04 to
Registration Statement No. 333-45206 and
incorporated by reference herein)
10.14 X Form of Severance Agreement between PSNC
and its Executive Officers (Filed as
Exhibit 10.05 to Registration Statement
No. 333-45206 and incorporated by
reference herein)
10.15 X Service Agreement between PSNC and SCANA
Services, Inc., effective April 1, 2000
(Filed as Exhibit 10.06 to Registration
Statement No. 333-45206 and incorporated
by reference herein)
10.16 X X Service Agreement between SCE&G and SCAN
Services, Inc., effective April 1, 2001
(Filed as Exhibit 10.16 to Form 10-Q for
the quarter ended September 30, 2001 and
incorporated by reference herein)
12.01 X X X Statement Re Computation of Ratios
23.01 X Consents of Experts and Counsel
(Independent Auditors' Consent)
23.02 X Consents of Experts and Counsel
(Independent Auditors Consent)
23.03 X Consents of Experts and Counsel
(Independent Auditors Consent)
23.04 X Consents of Experts and Counsel (Consent
of Independent Public Accountants)
24.01 X X X Power of Attorney (Filed herewith)
99.01 X Representation by Independent Public
Accountants