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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, 2002
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,
Series A liquidation value $25 South Carolina Electric & Gas Company
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 ( )
Public Service Company of North Carolina, Incorporated (x)
Indicate by check mark whether the registrants are accelerated filers
(as defined in Exchange Act Rule 12b-2).
SCANA Corporation Yes X No____.
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South Carolina Electric & Gas Company Yes X No____.
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Public Service Company of North Carolina, Incorporated Yes X No____.
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The aggregate market value of voting stock held by non-affiliates of
SCANA Corporation was $3.2 billion at June 28, 2002, based on a price of $30.87.
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 at February 28, 2003
- ---------- --------------------------- --------------------
SCANA Corporation Without Par Value 110,832,747
South Carolina Electric
and Gas Company $4.50 Par Value 40,296,147 (a)
Public Service Company of
North Carolina, Incorporated Without Par Value 1,000 (a)
(a) Held beneficially and of record by SCANA Corporation.
Documents incorporated by reference: Specified sections of SCANA
Corporation's 2003 Proxy Statement, in connection with its 2003 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 ............................................. 21
Item 3. Legal Proceedings....................................... 23
Item 4. Submission of Matters to a Vote of Security Holders .... 25
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................... 27
Item 6. Selected Financial Data................................. 29
SCANA Corporation....................................... 30
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................... 89
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... 129
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................... 154
PART III
Item 10. Directors and Executive Officers of the Registrants..... 154
Item 11. Executive Compensation ................................. 158
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters........ 162
Item 13. Certain Relationships and Related Transactions ......... 163
Item 14. Controls and Procedures.............................. 164
Item 15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K .................................. 164
SIGNATURES............................................................ 169
Certifications Required by Rule 13a-14......................... 172
Exhibit Index.................................................. 178
Certifications Pursuant to 18 U.S.C. Section 1350.............. 193
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 Construction
BTU............................... British Thermal Unit
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.................. The divisions of SEMI, excluding SCANA Energy
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
KW or KWh......................... Kilowatt or 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 or MWh......................... Megawatt or Megawatt hour
NCUC.............................. North Carolina Utilities Commission
NMST.............................. Negotiated Market Sales Tariff
NRC............................... United States Nuclear Regulatory Commission
PRP............................... Potentially Responsible Party
PSNC Energy....................... Public Service Company of North Carolina,
Incorporated
PUHCA............................. Public Utility Holding Company Act of 1935,
as amended
Santee Cooper..................... South Carolina Public Service Authority
SCANA............................. SCANA Corporation, the parent company
SCANA Energy...................... A division of SEMI which markets natural gas
in Georgia's retail natural gas market
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
SEMI.............................. SCANA Energy Marketing, Inc.
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 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 & SCANA COMMUNICATIONS, INC.
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GAS COMPANY Provides fiber optics telecommunications and
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Generates and sells electricity to wholesale data center facilities and builds, manages and leases
and retail customers and purchases, sells and communications towers in South Carolina, North
transports natural gas to wholesale and Carolina and Georgia. Through its Delaware
retail customers. subsidiary, SCANA Communications Holdings, Inc.,
holds investments in telecommunications companies.
SOUTH CAROLINA GENERATING
COMPANY, INC. SCANA ENERGY MARKETING, INC.
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Owns and operates Williams Station and Markets natural gas and wholesale electricity,
sells electricity to SCE&G. primarily in the Southeast. Provides energy-
related risk management services to producers
SOUTH CAROLINA FUEL and customers. Through its SCANA Energy
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COMPANY, INC. division, markets natural gas in Georgia's
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Acquires, owns and provides financing retail natural gas market.
for SCE&G's nuclear fuel, fossil fuel
and sulfur dioxide emission allowances. SERVICECARE, INC.
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Provides energy-related products and
PUBLIC SERVICE COMPANY OF service contracts on home appliances
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NORTH CAROLINA, INCORPORATED and heating and air conditioning units.
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Purchases, sells and transports
natural gas to retail customers and markets PRIMESOUTH, INC.
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natural gas. Provides management and maintenance services
for power plants and an alternate fuel facility.
SOUTH CAROLINA PIPELINE
CORPORATION SCANA RESOURCES, INC.
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Purchases, sells and transports natural Conducts energy-related businesses and
gas to wholesale and direct industrial provides energy-related services.
customers. Owns and operates two LNG
plants for the liquefaction, storage and SCANA SERVICES, INC.
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regasification of natural gas. Provides administrative, management and other
services to the subsidiaries and business units
SCG PIPELINE, INC. within SCANA Corporation.
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Organized to engage in the transportation of natural gas in Georgia
and South Carolina.
Each of SCANA and its direct, wholly owned subsidiaries is incorporated
under the laws of the State of South Carolina. SCANA also owns three
additional companies that are in liquidation.
RISK FACTORS
The risk factors that follow relate in each case to SCANA Corporation and
its subsidiaries, and where indicated the risk factors also relate to South
Carolina Electric and Gas Company (SCE&G) or Public Service Company of North
Carolina, Incorporated (PSNC Energy) or both.
Commodity price changes may affect the operating costs and competitive
positions of the energy business, thereby adversely impacting results of
operations.
The energy businesses of SCANA, SCE&G and PSNC Energy are sensitive to
changes in coal, gas, oil and other commodity prices. Any changes could affect
the prices these businesses charge, their operating costs and the competitive
position of their products and services. SCE&G is able to recover the cost of
fuel through retail customers' bills, but increases in fuel costs affect
electric prices and, therefore, the competitive position of electricity against
other energy sources. In the case of regulated natural gas operations at SCE&G
and PSNC Energy, costs for purchased gas and pipeline capacity are recovered
through retail customers' bills, but increases in gas costs affect total retail
prices and, therefore, the competitive position of gas relative to electricity,
other forms of energy and other gas suppliers.
SCANA, SCE&G and PSNC Energy are subject to complex government rate
regulation, which could adversely affect revenues and results of operations.
SCANA, SCE&G and PSNC Energy are subject to extensive regulation which
could adversely affect operations. In particular, SCE&G's electric operations in
South Carolina, and SCANA's gas operations in South Carolina (including SCE&G)
and North Carolina (PSNC Energy), are regulated by state utilities commissions.
Although we believe we have constructive relationships with our regulators, our
ability to obtain rate increases that will allow us to maintain our current rate
of return is dependent upon regulatory discretion, and there can be no assurance
that we will be able to implement requested rate increases on the schedule
desired. Moreover, in connection with our acquisition of PSNC Energy, PSNC
Energy agreed not to seek a general rate increase in the regulated North
Carolina gas market until 2005.
SCANA, SCE&G and PSNC Energy are vulnerable to interest rate increases and
may not have access to capital at favorable rates, if at all, which could
increase borrowing costs and adversely affect results of operations.
Changes in interest rates can affect the cost of borrowing on variable
rate debt outstanding, on refinancing of debt maturities and on incremental
borrowing to fund new investments. SCANA's business plan, and the business plans
of SCE&G and PSNC Energy, reflect the expectation that we will have access to
the equity and capital markets on satisfactory terms to fund commitments.
Moreover, the ability to maintain short-term liquidity by utilizing commercial
paper programs is dependent upon maintaining an investment grade rating. The
liquidity of SCANA, SCE&G and PSNC Energy would be adversely affected by changes
in the commercial paper market or if bank credit facilities become unavailable.
We may not be able to reduce our leverage as quickly as we have planned. This
could result in downgrades of our debt ratings, thereby increasing our borrowing
costs and adversely affecting our results of operations.
Our leverage ratio of debt to capital increased significantly following
our acquisition of PSNC Energy in 2000, and was approximately 60% at December
31, 2002. We have publicly announced our desire to reduce this leverage ratio to
between 50% to 52%, but our ability to do so depends on a number of factors. If
we are not able to reduce our leverage ratio, our debt ratings may be affected,
we may be required to pay higher interest rates on our long- and short-term
indebtedness, and our access to the capital markets may be limited.
Operating results may be adversely affected by abnormal weather.
SCANA, SCE&G and PSNC Energy have historically sold less power,
delivered less gas and received lower prices for natural gas, and consequently
earned less income, when weather conditions are milder than normal. Mild weather
in the future could diminish the revenues and results of operations and harm the
financial condition of SCANA, SCE&G and PSNC Energy. In addition severe weather
can be destructive, causing outages and property damage, adversely affecting
operating expenses and revenues.
Potential competitive changes may adversely affect gas and electricity
businesses due to the loss of customers, reductions in revenues, or write-down
of stranded assets.
The utility industry has been undergoing dramatic structural change for
several years, resulting in increasing competitive pressures on electric and
natural gas utility companies. Competition in wholesale power sales has been
introduced on a national level. Some states have also mandated or encouraged
competition at the retail level. Increased competition may create greater risks
to the stability of the utility earnings of SCE&G and PSNC Energy generally and
may in the future reduce earnings from retail electric and natural gas sales. In
a deregulated environment, formerly regulated utility companies that are not
responsive to a competitive energy marketplace may suffer erosion in market
share, revenues and profits as competitors gain access to their customers. In
addition, SCANA's and SCE&G's generation assets would be exposed to considerable
financial risk in a deregulated electric market. If market prices for electric
generation do not produce adequate revenue streams and the enabling legislation
or regulatory actions do not provide for recovery of the resulting stranded
costs, a write down in the value of these assets could be required.
SCANA, SCE&G and PSNC Energy are subject to risks associated with recent
events affecting capital markets and changes in business climate which could
limit access to capital, thereby increasing costs and adversely affecting
results of operations.
The September 11, 2001 attack on the United States and the ongoing war
against terrorism by the United States have resulted in greater uncertainty in
the financial markets. Additionally, the availability and cost of capital for
SCANA's, SCE&G's and PSNC Energy's businesses and those of our competitors could
be adversely affected by the bankruptcy of Enron Corporation and disclosures by
Enron and other energy companies of their trading practices involving
electricity and natural gas. These events have constrained and are expected to
continue to constrain the capital available to our industry and could limit our
access to funding for our operations. Other factors that generally could affect
our ability to access capital include: (1) general economic conditions; (2)
market prices for electricity and gas; and (3) our capital structure. Much of
our business is capital intensive, and achievement of our long-term growth
targets is dependent, at least in part, upon our ability to access capital at
rates and on terms we determine to be attractive. If our ability to access
capital becomes significantly constrained, our interest costs will likely
increase and our financial condition and future results of operations could be
significantly harmed.
SCANA, SCE&G and PSNC Energy do not fully hedge against price changes in
commodities. This could result in increased costs, thereby resulting in lower
margins and adversely affecting results of operations.
SCANA, SCE&G and PSNC Energy enter into contracts to purchase and sell
electricity and natural gas. We attempt to manage our exposure by establishing
risk limits and entering into contracts to offset some of our positions (i.e.,
to hedge our exposure to demand, market effects of weather and other changes in
commodity prices). However, we cannot always hedge the entire exposure of our
operations from commodity price volatility. To the extent we do not hedge
against commodity price volatility or our hedges are not effective, results of
operations and financial position may be diminished.
A downgrade in the credit rating of SCANA, SCE&G or PSNC Energy could
negatively affect its ability to access capital and to operate its businesses,
thereby adversely impacting results of operations and financial condition.
Standard & Poor's and Moody's rate SCANA's senior, unsecured debt at
BBB+ and A3, respectively, with a stable outlook. Standard & Poor's and Moody's
rate SCE&G's senior, secured debt at A- and A1, respectively, with a stable
outlook and rate PSNC Energy's senior, unsecured debt at A- and A2,
respectively, with a stable outlook. However, if Standard & Poor's or Moody's
were to downgrade any of these long-term ratings, particularly below investment
grade, borrowing costs would increase, which would diminish financial results,
and the potential pool of investors and funding sources could decrease. Further,
if short-term ratings for SCE&G or PSNC Energy were to fall below A-1 or P-1,
the current ratings assigned by Standard & Poor's and Moody's, respectively, it
could significantly limit access to the commercial paper market and liquidity.
Changes in the environmental laws and regulations to which SCANA, SCE&G and
PSNC Energy are subject could increase costs or curtail activities, thereby
adversely impacting results of operations and financial condition.
SCANA's, SCE&G's and PSNC Energy's compliance with extensive federal,
state and local environmental laws and regulations requires us to commit
significant capital toward environmental monitoring, installation of pollution
control equipment, emission fees and permits at our facilities. These
expenditures have been significant in the past and we expect that they will
increase in the future. Changes in compliance requirements or a more burdensome
interpretation by governmental authorities of existing requirements may impose
additional costs on us or require us to curtail some of our activities. Costs of
compliance with environmental regulations could harm our industry, our business
and our results of operations and financial position, especially if emission or
discharge limits are tightened, more extensive permitting requirements are
imposed or additional substances become regulated.
Changing transmission regulatory and energy marketing structures could
affect the ability of SCANA and SCE&G to compete in our electric markets,
thereby adversely impacting results of operations, cash flows and financial
condition.
The Federal Energy Regulatory Commission ("FERC") has issued a
Notice of Proposed Rulemaking ("NOPR") on Standard Market Design which proposes
sweeping changes to the country's existing regulatory framework governing
transmission, open access and energy markets and will attempt, in large measure,
to standardize the national energy market. While it is anticipated that
significant change to the NOPR may occur and that implementation, presently
scheduled for September 2004, may not occur for some time, any rules
standardizing the markets may have a significant impact on SCE&G's access to or
cost of power for its native load customers and for its marketing of power
outside its service territory. At this time, management is unable to predict the
final rules or timing of implementation and the impact on results of operations
and cash flows.
Repeal of PUHCA could adversely impact business by increasing costs or otherwise
changing or restricting the nature of activities in which SCANA, SCE&G and PSNC
Energy may engage. Any such changes could thereby impact results of operations.
SCANA is a registered holding company under the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"). Repeal of PUHCA has been proposed,
but it is unclear whether or when such a repeal would occur. It is also unclear
to what extent repeal of PUHCA would result in additional or new regulatory
oversight or action at the federal and state levels, or what the impact of those
developments might be on SCANA's business or that of SCE&G or PSNC Energy.
Problems with operations could cause us to incur substantial costs, thereby
adversely impacting our results of operations and financial condition.
As the operator of power generation facilities, SCE&G could incur
problems such as the breakdown or failure of power generation equipment,
transmission lines, other equipment or processes which would result in
performance below assumed levels of output or efficiency. The failure of a power
generation facility may result in SCE&G purchasing replacement power at market
rates. These purchases are subject to state regulatory prudency reviews for
recovery through rates.
SCANA is a holding company and its assets consist primarily of investments
in subsidiaries; covenants in certain of financial instruments may limit SCANA's
ability to pay dividends, thereby adversely impacting the valuation of our
common stock and our access to capital.
Our assets consist primarily of investments in subsidiaries. Dividends
on our common stock depend on the earnings, financial condition and capital
requirements of our subsidiaries, principally SCE&G and PSNC Energy. Our ability
to pay dividends on our common stock may also be limited by existing or future
covenants limiting the right of our subsidiaries to pay dividends on their
common stock. Any significant reduction in our payment of dividends in the
future may result in a decline in the value of our common stock. Such decline in
value could limit our ability to raise debt and equity capital.
A significant portion of SCE&G's generating capacity is derived from nuclear
power, the use of which exposes us to regulatory, environmental and business
risks. These risks could increase our costs or otherwise constrain our business,
thereby adversely impacting our results of operations and financial condition.
The V.C. Summer nuclear plant, operated by SCE&G, provided
approximately 4.5 million MWh, or 21% of our generation capacity, in 2002. Our
license to operate this plant currently expires in 2022. We have filed an
application with the federal NRC to extend the license for an additional 20
years, but there can be no assurance that the extension will be granted.
SCE&G is also subject to other risks of nuclear generation, which
include the following:
o The potential harmful effects on the environment and human health
resulting from a release of radioactive materials in connection with
the operation of nuclear facilities and the storage, handling and
disposal of radioactive materials;
o Limitations on the amounts and types of insurance commercially
available to cover losses that might arise in connection with our
nuclear operations or those of others in the United States;
o Uncertainties with respect to contingencies and assessment amounts if
insurance coverage is inadequate; and
o Uncertainties with respect to the technological and financial aspects
of decommissioning nuclear plants at the end of their licensed lives.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate capital expenditures at nuclear plants such as
ours. In addition, although we have no reason to anticipate a serious nuclear
incident, if a major incident should occur at a domestic nuclear facility, it
could harm our results of operations or financial condition. A major incident at
a nuclear facility anywhere in the world could cause the NRC to limit or
prohibit the operation or licensing of any domestic nuclear unit. Finally, in
today's environment, there is a heightened risk of terrorist attack on the
nation's nuclear facilities, which has resulted in increased security costs at
our nuclear plant.
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% of an indirect
subsidiary in liquidation. SCANA and its subsidiaries (the Company) had
full-time, permanent employees as of February 28, 2003 and 2002 of 5,361 and
5,369, 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, 2003 and 2002 of 2,875 and 2,657, respectively.
Prior to being acquired by SCANA in 2000, PSNC Energy was incorporated under the
laws of North Carolina in 1938. PSNC Energy is now incorporated under the laws
of South Carolina, and is an operating public utility in North Carolina with
full-time, permanent employees as of February 28, 2003 and 2002 of 758 and 652,
respectively.
INVESTOR INFORMATION
Information about SCANA and its businesses, including SCE&G and PSNC
Energy, is available on the Company's web site at www.scana.com. SCANA, SCE&G
and PSNC Energy annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports filed with the SEC
are available free of charge through this internet website as soon as reasonably
practicable after these reports are filed.
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. SCANA also has an investment in one LLC which owns
and operates a cogeneration facility in Charleston, South Carolina. SCANA also
has three other direct, wholly owned subsidiaries that are in liquidation.
Information with respect to major segments of business for the years
ended December 31, 2002, 2001 and 2000 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 for SCANA (Note 13),
SCE&G (Note 12) and PSNC Energy (Note 12). 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. 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 34 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 2.7 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.
Until October 2002 SCE&G operated a transit system in Columbia, South
Carolina. In October 2002 the transit system was transferred to the City of
Columbia, South Carolina (see discussion at Item 2, PROPERTIES - TRANSIT
PROPERTIES).
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.
PSNC Energy is a public utility engaged primarily in purchasing, selling
and transporting natural gas to approximately 384,000 residential, commercial
and industrial customers. PSNC Energy provides service to 27 of its 28
franchised counties covering approximately 12,000 square miles in North
Carolina. The industrial customers of PSNC Energy 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.
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.
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, Inc. at Elba Island, near Savannah, Georgia. In September 2002
SCG received approval from FERC to acquire an interest in an existing pipeline
and to build a pipeline from Elba Island, Georgia to Jasper County, South
Carolina. The endpoint of SCG's line will be at the site of the natural
gas-fired generating station that SCE&G is building in Jasper County.
Construction of the pipeline is expected to begin in the first half of 2003,
with completion expected in the fall of 2003.
Nonregulated Businesses
SEMI markets natural gas and wholesale electricity primarily in the
southeast and provides energy-related risk management services to producers and
customers. In addition, SCANA Energy, a division of SEMI, markets natural gas to
approximately 374,000 customers (as of December 31, 2002) in Georgia's natural
gas market.
SCI owns and operates a 500-mile fiber optic telecommunications network
in South Carolina and, through its affiliation with FRC, LLC, has an interest in
an additional 400 miles in South Carolina and North Carolina. SCI also provides
tower site construction, management and rental services in South Carolina and
North Carolina. SCI owned an 800 Mhz radio service network within South Carolina
which was sold to Motorola, Inc. in April 2002.
SCH, a Delaware corporation and a wholly owned subsidiary of SCI, holds
investments in ITC Holding Company, Inc., ITC^DeltaCom, Inc., and Knology, Inc.,
which are telecommunications services companies operating in the southeastern
United States. In December 2002, SCH completed the sale of its investment in
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. For additional information on the DTAG
sale, see Management's Discussion and Analysis of Financial Condition - Other
Matters for SCANA.
ServiceCare, Inc. is engaged primarily in providing homeowners with
energy-related products and service contracts on their home appliances and
heating and air conditioning units.
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, royalties and expense reimbursements 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 Energy.
CAPITAL REQUIREMENTS
The Company's cash requirements arise primarily from the operational
needs of SCANA's subsidiaries, the Company's construction program, the
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.
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
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 for SCANA (Note 4), SCE&G (Note 3) and PSNC
Energy (Note 5).
During the three-year period 2003-2005, the Company expects to meet its
capital requirements principally through internally generated funds
(approximately 71%, 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 2003-2005 are as follows:
- -------------------------------------- -------------- --------------
Type of Facilities 2005 2004 2003
- ------------------ ---- ---- ----
(Millions of dollars)
SCE&G:
Electric Plant:
Generation $58 $144 $382
Transmission 32 54 62
Distribution 103 109 106
Other 13 15 24
Nuclear Fuel 5 25 30
Gas 19 19 20
Common 12 11 23
Other 2 2 2
- -------------------------------------- -------------- --------------
Total SCE&G 244 379 649
PSNC Energy 39 39 45
Other Companies Combined 25 82 173
- -------------------------------------- -------------- --------------
Total $308 $500 $867
- -------------------------------------- -------------- --------------
CAPITAL PROJECTS
SCE&G placed in service a $264 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 341 MW of new electric generation and use exhaust heat to
replace a coal-fired steam boiler that powered two existing 75 MW turbines at
the Urquhart Generating Station.
In May 2002 SCE&G began construction of an 875 MW 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. The $450 million facility is
expected to begin commercial operation in mid-2004. SCG will transport natural
gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in
order to comply with new federal safety standards and maintain the lake in case
of an extreme earthquake. Construction for the project and related activities,
which began in the third quarter of 2001, are expected to cost approximately
$275 million and be completed in 2005.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the Lake Murray back-up dam.
The loan agreement provides for interest-free borrowings for costs incurred not
to exceed $59 million, and those borrowings must be repaid over ten years from
the initial borrowing. SCANA will be a guarantor of the loan. At December 31,
2002 SCE&G had not borrowed under the agreement.
In addition to the capital requirements and projects for 2003 described
above, the Company, SCE&G and PSNC Energy will require approximately $413.8
million, $144.6 million and $7.5 million, respectively, to refund and retire
outstanding long-term securities and obligations in 2003 including purchase or
sinking fund requirements for SCE&G's preferred stock. For the years 2004-2007,
the Company has an aggregate of $799.6 million of long-term debt and preferred
stock maturing, which includes an aggregate of $534.0 million for SCE&G, $2.2
million of purchase or sinking fund requirements for SCE&G's preferred stock and
$17.1 million for PSNC Energy. SCE&G's long-term debt maturities for the years
2004-2007 include approximately $141.9 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 Energy'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 Energy.
The Company's ratios of earnings to fixed charges were 0.53, 4.37, 2.47,
2.77 and 3.38 for the years ended December 31, 2002, 2001, 2000, 1999 and 1998,
respectively. To achieve a ratio of 1.0 for the year ended December 31, 2002,
the Company would have needed an additional $108.6 million in income from
continuing operations (pre-tax). The Company's ratio for 2002 decreased
significantly primarily due to the $230 million impairment for the acquisition
adjustment associated with PSNC Energy and the impairments of its investments in
certain telecommunications securities. The ratio for 2001 increased
significantly due primarily to the gain recognized on the exchange of the
Company's investment in Powertel, Inc. for DTAG. See Results of Operations. For
SCE&G these ratios were 3.47, 3.78, 4.24, 3.71 and 4.40 for the same periods.
For PSNC Energy these ratios were (7.78), 2.54 and 3.05 for the years ended
December 31, 2002, 2001 and 2000, respectively, and 3.18 and 3.22 for its fiscal
years ended September 30, 1999 and 1998, respectively. To achieve a ratio of 1.0
for the year ended December 31, 2002, PSNC Energy would have needed an
additional $193.2 million in income from continuing operations (pre-tax). PSNC
Energy's ratio decreased significantly primarily due to the $230 million
impairment for the acquisition adjustment described earlier. See Results of
Operations.
The Company has set a target ratio of debt to total capital of 50 to 52%.
At December 31, 2002, the ratio of debt to total capital was approximately 60%.
ELECTRIC OPERATIONS
Electric Sales
In 2002 SCE&G's residential sales of electricity accounted for 42% of
electric sales revenues; commercial sales 31%; industrial sales 19%; sales for
resale 4%; NMST 2%; and all other 2%. The Company's MWh sales by classification
for the years ended December 31, 2002 and 2001 are presented below:
MWh Sales (in thousands)
--------------------------------------------------------------------------
CLASSIFICATION 2002 2001 % CHANGE
---------------------------------- ---------------------------------------
Residential 7,230 6,494 11.3
Commercial 6,658 6,288 5.9
Industrial 6,505 6,347 2.5
Sales for resale 1,448 1,114 29.9
Other 535 534 0.2
---------------------------------- ---------------------
Total Territorial 22,376 20,777 7.7
NMST 709 2,151 (67.1)
---------------------------------- ---------------------
Total 23,085 22,928 0.7
================================== =====================
Sales for resale include sales to one municipality and three electric
cooperatives. Sales under the NMST during 2002 include sales to 37
investor-owned utilities and registered marketers, six electric cooperatives,
three municipalities and four federal/state electric agencies. During 2001 sales
under the NMST included sales to 39 investor-owned utilities and registered
marketers, four electric cooperatives, two municipalities and four federal/state
electric agencies.
The residential electric sales volume increased for 2002 primarily as a
result of favorable weather. During 2002 the Company recorded a net increase of
11,915 customers, increasing its total customers to 560,224 at year end. An
all-time peak demand of 4,404 MW was set on July 30, 2002. A new all-time peak
demand of 4,474 MW was set on January 24, 2003. The decrease in NMST volumes
reflects the Company's recording of buy-resale transactions in Other Income in
2002. Off-system sales (sales of electricity generated by the Company) continue
to be recorded in electric operations.
For the three-year period 2003-2005, the Company's total KWh sales of
electricity are projected to increase 2.1% annually. Residential KWh sales are
projected to increase 2.2% annually, commercial sales 2.2%, industrial sales
2.0%, sales for resale 2.2% and other sales 0.9%. The Company's total electric
customer base is projected to increase 1.6% annually. Over the same three-year
period, the Company's territorial peak load (summer, in MW) is projected to
increase 2.2% annually. The Company's goal is to maintain a reserve margin of
between 12% and 18%.
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. See
Electric Properties for Williams Station's generating capacity.
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 Order 2000 and
Standard Market Design 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 2000-2002.
Cost of Fuel Used
----------------------------------------------
2002 2001 2000
---- ---- ----
Per MMBTU:
Nuclear $.50 $.45 $.46
Coal - SCE&G 1.65 1.55 1.48
Coal - GENCO 1.70 1.52 1.51
All Fuels (weighted average) 1.48 1.33 1.31
Per Ton:
Coal - SCE&G $41.39 $38.70 $37.10
Coal - GENCO 43.30 39.23 38.98
Fuel Supply
The following table shows the sources and approximate percentages of
the Company's total MWh generation by each category of fuel for the years
2000-2002 and the estimates for the years 2003-2005.
% of Total MWh Generated
-----------------------------------------------------------
Estimated Actual
-------------------------------- --------------------------
2005 2004 2003 2002 2001 2000
---- ---- ---- -- ---- ---- - ----
Coal 61% 61% 67% 70% 75% 77%
Nuclear 18 21 20 21 21 18
Hydro 5 5 5 4 4 4
Natural Gas & Oil 16 13 8 5 - 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, 2002 SCE&G had approximately a 74-day supply of coal in
inventory and GENCO had approximately a 67-day supply.
Coal is obtained through supply 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 seven suppliers located in eastern
Kentucky, Tennessee and southwest Virginia. Contract commitments, which expire
at various times through 2004, are approximately 4.7 million tons annually,
which is 77% of total expected coal purchases for 2003. Sulfur restrictions on
the contract coal range from 0.75% to 1.6%.
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. See additional discussion at Environmental Matters in
Management's Discussion and Analysis of Financial Condition and Results of
Operations for the Company and SCE&G.
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) 17-20 2008
Fabrication Westinghouse Electric Corporation 17-22 2011
(1) A region represents approximately one-third to one-half of the nuclear
core in the reactor at any one time. Region 16 was loaded in 2002.
Region 17 will be loaded in 2003.
(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
2006 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, and Note 1N, New Accounting Standards related
to SFAS 143, of the Notes to Consolidated Financial Statements for SCANA and
SCE&G.
Other Significant Events
In August 2002 SCE&G filed an application with the NRC for a 20-year
license extension for its Summer Station. If approved, the extension would allow
the plant to operate through 2042.
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over seven years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City.
SCE&G will also pay the Central Midlands Regional Transit Authority up to $3
million as matching funds for Federal Transit Administration grants for the
purchase of new transit coaches and a new transit facility.
GAS OPERATIONS
For the three-year period 2003-2005, the Company's total consolidated
sales of natural gas in DTs are projected to increase 1.2% annually. Residential
DT sales are projected to increase 2.6% annually, commercial sales 1.7% and
industrial sales 0.1%. Sales for resale are not expected to increase. The
Company's total consolidated natural gas customer base is projected to increase
2.5% annually.
Gas Sales - Regulated
In 2002 the Company's residential sales accounted for 38.3% of gas
sales revenues; commercial sales 21.1%; industrial sales 28.4%; sales for resale
8.3 %; and transportation sales 3.9%. During the same period, SCE&G's
residential sales accounted for 41.3% of gas sales revenues; commercial sales
32.8%, industrial sales 24.7% and transportation sales 1.2%. Also during the
same period, PSNC Energy's residential sales accounted for 60.1% of gas sales
revenues; commercial sales 24.7%; industrial sales 7.1%; and transportation
sales 8.1%. DT sales by classification for the years ended December 31, 2002 and
2001 are presented below:
Dekatherms Sales (in thousands)
- -------------------------------------------------------------------------------------------------------------------------------
The Company SCE&G PSNC Energy
% % %
CLASSIFICATION 2002 2001 Change 2002 2001 Change 2002 2001 Change
- -------------------------- ---------- ---------- ----------- ------------- --------- ---------- --------- --------- -----------
Residential 35,673 31,966 11.6 12,242 11,256 8.8 23,431 20,710 13.1
Commercial 25,046 23,652 5.9 11,718 11,305 3.7 13,209 12,278 7.6
Industrial 58,999 47,901 23.2 15,939 14,301 11.5 5,308 5,277 0.6
Sales for Resale 15,722 14,827 6.0 n/a n/a n/a n/a n/a
n/a
Transportation Gas 31,550 28,706 9.9 2,373 2,461 (3.6) 27,793 25,719 8.1
------ ------ ----- ----- ------ ------
Total 166,990 147,052 13.6 42,272 39,323 7.5 69,741 63,984 9.0
========================== ========== ========== =========== ============= ========= ========== ========= ========= ===========
The Company's DT sales noted above include SCPC sales of 107,359
thousand DTs and 84,840 thousand DTs for 2002 and 2001, respectively (including
transactions with affiliates). The Company's and SCE&G's gas sales volume
increased for 2002 primarily as a result of more favorable weather. During 2002
the Company recorded a net increase of approximately 21,100 gas customers,
increasing its gas customers to approximately 666,868. SCE&G recorded a net
increase of approximately 4,900 gas customers, increasing its total gas
customers to approximately 272,100. PSNC Energy recorded a net increase of
approximately 14,800 customers, increasing its total customers to approximately
383,900.
The demand for gas is affected by the weather, the price relationship
between gas and alternate fuels and other factors.
SCPC, operating wholly within South Carolina, provides natural gas
utility and transportation services for its direct industrial customers, and
supplies natural gas to SCE&G and other wholesale purchasers. SEMI 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, 2006
and 2007) 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. Of these amounts, 3.5 MMCF from
Southern Natural and 1.9 MMCF from Transco have been temporarily released to the
City of Orangeburg for a period of two years. SCPC also has an additional firm
service contract with Southern Natural (expiring in 2017) for 50 MMCF which is
directly assigned to SCE&G for use in electric generation. 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 DTs for resale to SCE&G's customers.
The contract allows SCE&G to receive amounts in excess of this demand based on
availability.
During 2002 SCPC's average cost per MCF of natural gas purchased for
resale, including firm service demand charges, was $4.40 compared to $5.47
during 2001. SCE&G's average cost per MCF was $5.32 and $6.91 during 2002 and
2001, respectively.
SCPC's tariffs include a purchased gas adjustment (PGA) clause that
provides for the recovery of actual gas costs incurred. The SCPSC has ruled that
the results of SCPC's hedging activities are to be included in the PGA. As such,
costs of related derivatives are recoverable through its weighted average cost
of gas calculation. The offset to the change in fair value of these derivatives
is recorded as a regulatory asset or liability.
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 liquefaction and storage facilities. The LNG plants are capable of
storing the liquefied equivalent of 1,880 MMCF of natural gas. Approximately
1,587 MMCF of gas were in storage at December 31, 2002. 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 5,688 MMCF of gas
were in storage on December 31, 2002.
The SCPSC has established allocation priorities applicable to the firm
and interruptible capacities of SCPC. These curtailment plan priorities apply to
SCPC's direct industrial customers and resale distribution customers, including
SCE&G.
North Carolina
PSNC Energy purchases natural gas under contracts with producers and
marketers on a short-term basis at current price indices and on a long-term
basis for reliability assurance at index prices plus a reservation charge. The
gas is brought to North Carolina through transportation agreements with Transco
and Dominion Transmission, Inc. with expiration dates ranging through 2016. The
daily volume of gas that PSNC Energy is entitled to transport under these
contracts on a firm basis is 259,894 DT from Transco and 30,331 DT from Dominion
Transmission. PSNC Energy has executed precedent agreements for firm
transportation service on the Patriot Extension Project, a project of East
Tennessee Natural Gas Company, and for firm storage service on the Saltville
Storage Project, an affiliate of East Tennessee Natural Gas Company, that
provide daily demand of 30,000 DT. These agreements will meet incremental
capacity requirements beginning in November 2003. PSNC Energy also has executed
an agreement for firm transportation service that provides daily demand of
70,000 DT on the Greenbrier Pipeline Project, a project of Dominion
Transmission. This agreement will meet incremental capacity requirements
beginning in November 2005.
During 2002 PSNC Energy's average cost per DT of natural gas purchased
for resale, including firm service demand charges, was $5.03, compared to $6.50
during 2001.
To meet the requirements of its high priority natural gas customers
during periods of maximum demand, PSNC Energy supplements its supplies of
natural gas with underground natural gas storage services and LNG peaking
services. Underground natural gas storage service agreements with Dominion Gas
Transmission, Columbia Gas Transmission and Transco provide for storage capacity
of approximately 11,318 MMCF. Approximately 8,671 MMCF were in storage at
December 31, 2002. In addition, PSNC Energy'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 786 MMCF were in storage at
December 31, 2002. LNG storage service agreements with Transco, Cove Point LNG
and Pine Needle LNG provide for approximately 1,266 MMCF of storage space.
Approximately 1,154 MMCF were in storage at December 31, 2002.
The Company, SCE&G and PSNC Energy believe 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
SEMI's activities are primarily focused in the Southeast, where SEMI
markets natural gas and provides energy-related risk management services to
producers and consumers. SEMI is also a power marketer, which allows it to buy
and sell electric capacity in wholesale markets. In addition, SCANA Energy, a
division of SEMI, markets natural gas to approximately 374,000 customers (as of
December 31, 2002) in Georgia's natural gas market.
Policies and procedures and risk limits are established to control the
level of market, credit, liquidity and operational and administrative risks
assumed by the Company. The Company's Board of Directors has delegated to a Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and oversee and review the risk
management process and infrastructure. The Risk Management Committee, which is
comprised of certain officers, including the Company's Risk Management Officer
and senior officers of the Company, provides assurance to the Board of Directors
with regard to the management of risk and brings to the Board's attention any
areas of concern. Written policies define the physical and financial
transactions that are approved, as well as the authorization requirements and
limits for transactions that are allowed.
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
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.
PSNC Energy 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.
SCANA Energy is subject to the jurisdiction of the GPSC as to gas rates
for certain of its low-income customers and those that pose a known high credit
risk. At December 31, 2002 SCANA Energy served approximately 11,000 such
customers.
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. (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
Saluda 2007 Stevens Creek 2025
Fairfield Pumped Storage 2020 Neal Shoals 2036
Parr Shoals 2020
SCE&G transferred the Columbia Project to the City of Columbia, South
Carolina (City) in October 2002 in connection with SCE&G's transfer of its
transit system to the City. SCE&G will continue to operate the plant for the
City until 2005. See ITEM 2, PROPERTIES.
In January 2003 SCE&G filed with FERC a motion for a five year
extension for the Saluda Project due to the FERC mandated Lake Murray draw down.
The draw down of Lake Murray will affect the mandated studies of normal lake
conditions. The five year extension will allow time for the lake level to return
to normal operating conditions and to stabilize in order to conduct meaningful
studies that may impact future license requirements. For a discussion of SCE&G's
agreement with FERC related to reinforcing the Lake Murray dam (related to the
Saluda 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.
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.
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 Order 2000 and Standard Market Design
The Company's regulated business operations were impacted by FERC Order
No. 2000 and other related initiatives of the FERC. Order No. 2000 required each
utility under FERC jurisdiction that operates an electric transmission system to
submit plans for the possible formation of a regional transmission organization.
In March 2001, FERC gave provisional approval to SCE&G and two other
southeastern electric utilities to establish GridSouth as an independent
regional transmission company, responsible for operating and planning the
utilities' combined transmission systems. In June 2002 GridSouth implementation
was suspended pending the issuance and evaluation of new FERC directives.
In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on
Standard Market Design which proposes sweeping changes to the country's existing
regulatory framework governing transmission, open access and energy markets and
which will attempt, in large measure, to standardize the national energy market.
While it is anticipated that significant changes to the NOPR may occur and that
implementation, presently scheduled for September 2004, may not occur for some
time, any rules standardizing the markets may have significant impact on the
Company's access to or cost of power for its native load customers and on the
Company's marketing of power outside its service territory. The Company is
currently evaluating this NOPR to determine what effect it will have on its
operations. Additional directives from FERC are expected later in 2003.
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 for SCANA
(Note 4), SCE&G (Note 3) and PSNC Energy (Note 5).
General
SCE&G's and PSNC Energy's gas rate schedules for their residential and
small commercial customers include a WNA. SCE&G's and PSNC Energy's WNA were
approved by the SCPSC and NCUC, respectively, and are in effect for bills
rendered during the period November 1 through April 30 of each year. In each
case the WNA increases tariff rates if weather is warmer than normal and
decreases rates if weather is colder than normal. The WNA does not change the
seasonality of gas revenues; 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 2002 annual review of the fuel cost
component of electric rates, the SCPSC increased the fuel cost component of the
electric rate to 1.722 cents per KWh. In January 2003, in conjunction with the
approval of the retail rate increase, the SCPSC approved SCE&G's request to
reduce the fuel component to 1.678 cents 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 the actual 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 Energy operates under two rate provisions in addition to WNA that
serve to reduce fluctuations in PSNC Energy's earnings. First, its Rider D rate
mechanism allows PSNC Energy to recover, in any manner authorized by the NCUC,
margin losses on negotiated gas sales. The Rider D rate mechanism also allows
PSNC Energy to recover from customers all prudently incurred gas costs,
including changes in natural gas prices. Second, PSNC Energy operates with full
margin transportation rates. These rates allow PSNC Energy to earn the same
margin on gas delivered to customers regardless of whether the gas is sold or
only transported by PSNC Energy to the customer.
PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually.
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 Energy, 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 2000 through 2002, the Company's capital expenditures for
environmental control totaled approximately $133.9 million (including
approximately $122.3 million for SCE&G). These expenditures were in addition to
expenditures included in "Other operation and maintenance" expenses, which were
approximately $29.9 million, $23.0 million, and $19.6 million during 2002, 2001
and 2000, respectively (including approximately $23.7 million, $17.0 million and
$16.6 million for SCE&G during 2002, 2001 and 2000, respectively). It is not
possible to estimate all future costs for environmental purposes, but forecasts
for capitalized environmental expenditures for the Company are $116.7 million
for 2003 and $94.7 million for the four-year period 2004 through 2007 (including
$56.8 million for 2003 and $32.0 million for the four-year period 2004 through
2007 for SCE&G). These expenditures are included in the Company's and SCE&G's
construction program.
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 12B for the
Company and Note 11B for SCE&G), which are incorporated herein by reference.
For a description of the Company's investments in various
telecommunications companies, see Other Matters - Telecommunications Investments
in 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. 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% of an indirect subsidiary in
liquidation. It also has an investment in one LLC which operates a cogeneration
facility in Charleston, South Carolina.
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) (MW)
-------- --------------- -------- ---------- --------------------
Steam
-----
Urquhart (1) Coal/Gas Beech Island, SC 1953/2002 570
McMeekin Coal/Gas Irmo, SC 1958 250
Canadys Coal/Gas Canadys, SC 1962 407
Wateree Coal Eastover, SC 1970 700
Williams (2) Coal Goose Creek, SC 1973 615
Summer (3) Nuclear Parr, SC 1984 644
D-Area (4) Coal DOE Savannah River Site, SC 1995 35
Cope Coal Cope, SC 1996 410
Cogen South * Charleston, SC 1999 90
Gas Turbines
------------
Burton Gas/Oil Burton, SC 1961 27
Faber Place Gas Charleston, SC 1961 8
Hardeeville Oil Hardeeville, SC 1968 12
Urquhart Gas/Oil Beech Island, SC 1969 40
Coit Gas/Oil Columbia, SC 1969 32
Parr Gas/Oil Parr, SC 1970 69
Williams Gas/Oil Goose Creek, SC 1972 40
Hagood Gas/Oil Charleston, SC 1991 86
Urquhart #4 Gas/Oil Beech Island, SC 1999 51
Jasper (5) Gas/Oil Hardeeville, SC - -
Hydro
-----
Neal Shoals Carlisle, SC 1905 5
Parr Shoals Parr, SC 1914 15
Stevens Creek Martinez, GA 1914 12
Columbia (6) Columbia, SC 1927 10
Saluda Irmo, SC 1930 206
Pumped Storage
--------------
Fairfield Parr, SC 1978 544
------
4,878
(1) SCE&G placed in service in June 2002 a gas turbine generator project.
Two combined-cycle turbines burn natural gas or fuel oil to produce 341
MW of new electric generation and use exhaust heat to replace
coal-fired steam that powers two existing 75 MW turbines at the
Urquhart Generating Station. Unit 3 remains as the only coal-fired
steam unit at the site.
(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.
Although a formal contract is required, DOE has indicated orally and in
writing their intention to extend the contract with SCE&G to October 1,
2014.
(5) SCE&G is currently constructing a combined cycle generating facility in
Jasper County. This facility is scheduled to begin operation in
mid-2004 and will produce 875 MW of electric energy.
(6) Columbia Hydro was conveyed to the City of Columbia in October 2002 as
part of a franchise agreement. SCE&G will continue to operate the plant
for the City until 2005.
* SCE&G receives shaft horse power from Cogen South, LLC to operate
SCE&G's generator. Cogen South, LLC is owned 50% by SCANA and 50% by
MeadWestvaco.
SCE&G owns 445 substations having an aggregate transformer capacity of
22.7 million KVA (kilovolt-ampere). The transmission system consists of 3,165
miles of lines and the distribution system consists of 17,166 pole miles of
overhead lines and 4,363 trench miles of underground lines.
NATURAL GAS PROPERTIES
SCE&G's natural gas system consists of approximately 13,006 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 70 MMCF per day. These facilities
can store the equivalent of 298 MMCF of natural gas.
SCPC's natural gas system consists of approximately 1,965 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 Energy's natural gas system consists of approximately 803 miles of
transmission pipeline of up to 24 inches in diameter that connect its
distribution systems with Transco. PSNC Energy's distribution system consists of
approximately 7,637 miles of distribution mains and related service facilities.
PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the
capacity to liquefy approximately 100 MMCF per day. PSNC Energy also owns,
through a wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC,
which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC
Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company,
LLC. Pine Needle owns and operates a liquefaction, storage and regasification
facility in North Carolina.
In September 2002 SCG received approval from FERC to purchase an
undivided ownership interest in the Southern Natural Gas 13.25 mile, 30-inch
diameter parallel pipelines, the Twin 30s, and associated rights-of-way and
permits, equivalent to the capacity of 190,000 MCF per day. The Twin 30s extend
from Elba Island to Port Wentworth, Georgia. This pipeline is the sole means by
which regasified LNG is transported from Southern Natural's LNG facility.
FERC also approved SCG's proposal to construct 18.2 miles of 20 inch
diameter transmission pipeline and appurtenant facilities from an
interconnection with the Twin 30s at Port Wentworth in Chatham County, Georgia
to the natural gas-fired generating station that SCE&G is building in Jasper
County, South Carolina. Construction of the pipeline is expected to begin in the
first half of 2003.
TRANSIT PROPERTIES
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over eight years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City.
SCE&G will continue to operate the plant for the City until 2005. SCE&G will
also pay the Central Midlands Regional Transit Authority up to $3 million as
matching funds for Federal Transit Administration grants for the purchase of new
transit coaches and a new transit facility.
ITEM 3. LEGAL PROCEEDINGS
The following Legal Proceedings were pending at December 31, 2002.
These proceedings affect the Company and, to the extent indicated, they also
affect SCE&G or PSNC Energy.
Rate and Other Regulatory Matters
In January 2003 the SCPSC issued an order granting SCE&G an
increase in retail electric rates of 5.8% which is designed to produce
additional annual revenues of approximately $70.7 million based on a test year
calculation. The SCPSC authorized a return on common equity of 12.45%. The new
rates were effective for service rendered on and after February 1, 2003. As a
part of the order, the SCPSC extended through 2005 its approval of the
accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the
plan, SCE&G may increase depreciation of its Cope Generating Station in excess
of amounts that would be recorded based upon currently approved depreciation
rates, 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.
PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually. On January 2, 2003 the NCUC issued an order approving PSNC
Energy's request to increase the benchmark cost of gas from $0.410 to $0.460
rate per therm effective for service rendered on and after January 1, 2003. On
March 3, 2003 the NCUC approved PSNC Energy's request to increase the benchmark
cost of gas to $0.595 per therm effective March 1, 2003.
Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its 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 approximately $275 million and be completed in 2005.
Environmental Matters
SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the
Calhoun Park 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 before 2006. As of December 31, 2002 SCE&G had
spent approximately $2.2 million related to these sites and expects to spend an
additional $5.9 million.
PSNC Energy 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 Energy'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. In September 2002 an allocation agreement was reached relieving PSNC
Energy of liability for two of the seven sites. PSNC Energy has recorded a
liability and associated regulatory asset of $7.8 million, which reflects the
estimated remaining liability at December 31, 2002. Amounts incurred through
December 31, 2002 that have not been recovered through gas rates are
approximately $1.2 million. Management believes that all MGP cleanup costs
incurred will be recoverable through gas rates.
Pending or Threatened Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of
SCANA filed suit against SCANA in South Carolina 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.
In 2001 the Company entered into, in the ordinary course of business, a
15 year take-and-pay contract with an unaffiliated natural gas supplier
(Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring
of 2004. In December 2002, as a result of the failure of Supplier and its
guarantor to meet contractual obligations related to credit support provisions,
the Company terminated the contract. Attempts to negotiate a new contract
between the parties were not successful. In February 2003, the Company received
notification from Supplier of its request for binding arbitration under the
original contract. The Company is confident of the propriety of its actions and
will vigorously pursue its position in such arbitration proceedings. The Company
further believes that the resolution of these claims will not have a material
adverse impact on its results of operations, cash flows or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
EXECUTIVE OFFICERS OF SCANA CORPORATION
The executive officers are elected at the annual meeting of the Board
of Directors, held immediately after the annual meeting of shareholders, and
hold office until the next such annual meeting, unless a resignation is
submitted, or unless the Board of Directors shall otherwise determine. Positions
held are for SCANA and all subsidiaries unless otherwise indicated.
Name Age Positions Held During Past Five Years Dates
W. B. Timmerman 56 Chairman of the Board, President and Chief Executive Officer *-present
H. T. Arthur 57 President and Chief Operating Officer - SEMI 2002-present
Senior Vice President-General Counsel and Assistant Secretary 1998-present
Vice President-General Counsel and Assistant Secretary *-1998
G. J. Bullwinkel 54 President and Chief Operating Officer - SCPC and ServiceCare 2002-present
President and Chief Operating Officer- SCI *-present
Senior Vice President-Governmental Affairs and Economic Development 1999-2002
Senior Vice President - Retail Electric-SCE&G *-1999
S. D. Burch 46 Senior Vice President-Natural Gas Asset and Procurement Management 2003-present
Deputy General Counsel and Assistant Secretary 2000-2003
Attorney *-2000
S. A. Byrne 43 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
D. C. Harris 50 Senior Vice President - Human Resources 2000-present
Vice President - Human Resources-Austin Quality Foods, Inc. Cary, NC *-2000
N. O. Lorick 52 President and Chief Operating Officer-SCE&G 2000-present
Vice President - Fossil and Hydro Operations-SCE&G *-2000
K. B. Marsh 47 Senior Vice President and Chief Financial Officer 1998-present
President and Chief Operating Officer-PSNC Energy 2001-2003
Vice President - Finance and Chief Financial Officer *-1998
Controller *-2000
C. B. McFadden 58 Senior Vice President-Governmental Affairs and Economic Development 2003-present
Vice President-Governmental Affairs and Economic Development *-2003
* Indicates position held at least since March 1, 1998.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
COMMON STOCK INFORMATION - SCANA Corporation
------------------ ------------------------------------------------- ------------------------------------------------
2002 2001
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------
------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ -----------
Price Range: (a)
High $31.00 $31.26 $32.15 $30.66 $27.99 $28.49 $29.03 $30.00
Low 24.80 23.50 29.05 26.26 25.00 24.25 26.61 24.92
------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ -----------
(a) As reported on the New York Stock Exchange Composite Listing.
------------------------------ ------------------ ------------------ ----------- ------------------ -----------------
DIVIDENDS PER SHARE 2002 2001
------------------------------ ------------------ ------------------ ------------------ -----------------
-----------
Amount Date Declared Date Paid Amount Date Declared Date Paid
------ ------------- --------- ------ ------------- ---------
First Quarter $.325 February 21, 2002 April 1, 2002 $.30 February 22, 2001 April 1, 2001
Second Quarter .325 May 2, 2002 July 1, 2002 .30 May 3, 2001 July 1, 2001
Third Quarter .325 August 1, 2002 October 1, 2002 .30 August 2, 2001 October 1, 2001
Fourth Quarter .325 October 31, 2002 January 1, 2003 .30 November 1, 2001 January 1, 2002
----------------- ------------ ------------------ ------------------ ----------- ------------------ -----------------
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, 2003 was 110,832,747. The number of common
shareholders of record at February 28, 2003 was 40,170.
All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has
no market. During 2002 and 2001 SCE&G paid $152.5 million and $157.3 million,
respectively, in cash dividends to SCANA. During 2002 and 2001 PSNC Energy
paid $14.5 million and $18.3 million, respectively, in cash
distributions/dividends to SCANA.
SECURITIES RATINGS (As of February 28, 2003)
SCANA SCE&G PSNC Energy
---------------------------- ----------------------------------------------------------- ---------------------------
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 Baa1 A3 P-1 A2 P-1
Standard & BBB+ A- A- BBB BBB A-1 A- A-1
Poors
---------------- ----------- ----------- ----------- ---------- ----------- ------------ ------------- -------------
Additional information regarding these debt and equity securities can be
found in the Notes to Consolidated Financial Statements for SCANA (Notes 6, 7
and 9), SCE&G (Notes 5, 6 and 8) and PSNC Energy (Notes 7 and 8).
The Restated Articles of Incorporation of SCE&G 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, 2002 approximately $40.6 million of retained
earnings were restricted by this requirement as to payment of cash dividends
on common stock of SCE&G.
Equity securities issuable under the Company's compensation plans at
December 31, 2002 are summarized as follows:
Equity Compensation Plan Information
Number of securities
Number of securities remaining available for
to be issued Weighted-average future issuance under
upon exercise of exercise price of equity compensation plans
outstanding options, outstanding options, (excluding securities
Plan Category warrants and rights warrants and rights reflected in column (a))
- --------------------------------------- ------------------------ -------------------- ----------------------------
- --------------------------------------- ------------------------ -------------------- ----------------------------
(a) (b) (c)
Equity compensation plans approved
by security holders 1,717,910 $26.96 3,980,199
Equity compensation plans not
approved by security holders (1) n/a n/a 35,188
Total 1,717,910 $26.96 4,015,387
(1) Consists solely of the SCANA Corporation Director Compensation and Deferral
Plan. Non-employee directors receive an annual retainer, of which 60% is
required to be paid in SCANA Common Stock. Non-employee directors may elect to
receive the remaining retainer and any meeting attendance and conference fees in
SCANA Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
SCANA
- ---------------------------------------------------------------- -------------- ---------- ---------- ---------- ----------- ---
As of or for the Year Ended December 31, 2002 2001 2000(1) 1999 1998
- ---------------------------------------------------------------- -------------- ---------- ---------- ---------- ----------- ---
(Millions of dollars, except statistics and per share amounts)
Statement of Income Data
Operating Revenues $2,954 $3,451 $3,433 $2,078 $2,106
Operating Income 514 528 554 353 470
Other Income (Expense) (180) 550 44 90 19
Income Before Cumulative Effect of Accounting Change 88 539 221 179 223
Net Income (Loss)(2) (142) 539 250 179 223
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions) 106.0 104.7 104.5 103.6 105.3
Basic and Diluted Earnings (Loss) Per Share (2) $(1.34) $5.15 $2.40 $1.73 $2.12
Dividends Declared Per Share of Common Stock $1.30 $1.20 $1.15 $1.32 $1.54
Balance Sheet Data
Utility Plant, Net $5,474 $5,263 $4,949 $3,851 $3,787
Total Assets 7,754 7,822 7,427 6,011 5,281
Capitalization:
Common equity $2,177 $2,194 $2,032 $2,099 $1,746
Preferred Stock (Not subject to purchase or sinking 106 106 106 106 106
funds)
Preferred Stock, net (Subject to purchase or sinking 9 10 10 11 11
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 2027 50 50 50 50 50
Long-term Debt, net 2,834 2,646 2,850 1,563 1,623
- ---------------------------------------------------------------- -------------- ---------- ---------- ---------- -----------
- ---------------------------------------------------------------- -------------- ---------- ---------- ---------- ---
Total Capitalization $5,176 $5,006 $5,048 $3,829 $3,536
================================================================ ============== ========== ========== ========== =========== ===
Other Statistics (3)
Electric:
Customers (Year-End) 560,224 547,388 537,253 523,552 517,447
Total sales (Million KWh) 23,085 22,928 23,352 21,744 21,203
Generating capability - Net MW (Year-End) 4,866 4,520 4,544 4,483 4,387
Territorial peak demand - Net MW 4,404 4,196 4,211 4,158 3,935
Regulated Gas:
Customers (Year-End) 666,868 645,749 637,018 260,456 257,051
Sales, excluding transportation (Thousand Therms) 1,356,039 1,183,463 1,389,975 1,013,083 1,002,952
Retail Gas Marketing:
Retail customers (Year-End) 374,347 385,581 431,814 430,950 78,091
Firm customer deliveries (Thousand Therms) 337,858 359,602 431,115 229,660 4,692
Nonregulated interruptible customer deliveries (Thousand 514,731 407,188 306,099 188,828 2,167,931
Therms)(4)
- ---------------------------------------------------------------- -------------- ---------- ---------- ---------- ----------- ---
SCE&G
- ------------ ---------- --------- ---------- ----------
2002 2001 2000 1999 1998
- ------------ ---------- --------- ---------- ----------
$1,683 $1,715 $1,669 $1,465 $1,450
417 428 457 393 448
37 30 16 12 9
219 222 231 189 227
219 222 253 189 227
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
$4,351 $3,891 $3,615 $3,501 $3,432
5,552 4,962 4,671 4,404 4,246
$1,966 $1,750 $1,657 $1,558 $1,499
106 106 106 106 106
9 10 10 11 11
50 50 50 50 50
1,534 1,412 1,267 1,121 1,206
- ------------ ---------- --------- ---------- ----------
- ------------ ---------- --------- ---------- ----------
$3,665 $3,328 $3,090 $2,846 $2,872
============ ========== ========= ========== ==========
553,948 547,411 537,286 523,581 517,472
23,086 22,928 23,353 21,746 21,204
4,251 3,905 3,929 3,883 3,807
4,404 4,196 4,211 4,158 3,935
272,154 267,206 266,451 260,348 256,843
398,991 368,632 444,521 414, 800 405,249
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 Energy effective January 1, 2000. (2)
Reflects write-down for goodwill impairment in 2002 for adoption of SFAS 142.
(3) Other Statistics for 2000 exclude the effect of the change in accounting for
unbilled revenues, where applicable. (4) Interruptible deliveries for 1998
includes volumes from the Houston office of SEMI, which was closed in 1999.
SCANA CORPORATION
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 53
Item 8. Financial Statements and Supplementary Data................... 55
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 and marketability of the Company's
investments in telecommunications companies, (10) performance of the Company's
pension plan assets, (11) inflation, (12) changes in environmental regulations,
(13) volatility in commodity natural gas markets and (14) 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
In South Carolina, electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2003.
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. In view of
the potential for deregulation, the Company has continued efforts to renew
franchise agreements with municipalities within its current service area.
Effective October 2002, SCE&G secured a 30-year franchise to provide the City of
Columbia, South Carolina, with electric and natural gas services. Columbia is
one of the largest cities in SCE&G's service area. Previously, SCE&G reached
franchise agreements with the cities of North Charleston (franchise expires in
2021), Charleston (franchise expires in 2026) and numerous other municipalities.
In addition, in May 2001 SCE&G signed an electric supply contract with North
Carolina Electric Membership Corporation to supply 350 MW in each of 2004 and
2005 and 250 MW annually in 2006 through 2012. These energy sales are recallable
for SCE&G's native load, if necessary.
At the federal level, energy legislation passed both houses of Congress
in 2002, though significant differences between the House and Senate versions
were not reconciled before the legislative session adjourned. Some of the more
stringent provisions of this legislation would have required, among other
things, that one percent of the electric energy sold by retail electric
suppliers, beginning in 2005, escalating to ten percent in 2019, be generated
from renewable energy resources. Renewable energy resources, as defined in some
versions of the legislation, would have excluded hydroelectric generation.
Substantial penalties would have been levied for failure to comply. Electric
cooperatives and municipal utilities would have been exempt from these
requirements. The Company expects similar legislation will be introduced in
Congress in 2003. The Company cannot predict whether such legislation will be
enacted, and if it is, the conditions it would impose on utilities.
In June 2002 implementation of GridSouth Transco LLC (GridSouth) was
suspended pending the issuance and evaluation of new FERC directives. In July
2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market
Design which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. While it
is anticipated that significant change to the NOPR may occur and that
implementation, presently scheduled for September 2004, may be delayed, any
rules standardizing the markets may have a significant impact on SCE&G's access
to or cost of power for its native load customers and on SCE&G's marketing of
power outside its service territory. The Company is currently evaluating this
NOPR to determine what effect it will have on SCE&G's operations. Additional
directives from FERC are expected in 2003.
Gas Distribution
The Company has secured franchise agreements with several municipalities
within its current service areas to provide natural gas services. See previous
discussion at Electric Operations. Natural gas competes with electricity,
propane and heating oil to serve the heating and, to a lesser extent, the other
household energy needs of residential and small commercial customers. This
competition is generally based on price and convenience. Large commercial and
industrial customers often have the ability to switch from natural gas to an
alternate fuel, such as propane or fuel oil. Natural gas competes with these
alternate fuels based on price. As a result, any significant disparity between
supply and demand, either of natural gas or of alternate fuels, and due either
to production or delivery disruptions or other factors, will affect the price
and impact the Company's ability to retain large commercial and industrial
customers on a monthly basis.
Gas Transmission
In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to
acquire an interest in an existing pipeline and to build a pipeline from Elba
Island, Georgia to Jasper County, South Carolina. When operational, SCG 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, Inc. at Elba Island, near Savannah,
Georgia. The endpoint of SCG's pipeline will be at the site of the natural
gas-fired generating station that SCE&G is building in Jasper County, South
Carolina. Construction of the pipeline is expected to begin in the first half of
2003, with completion expected in the fall of 2003.
SCPC supplies natural gas to SCE&G, for its resale to gas distribution
customers and for certain electric generation needs. Gas transmission also sells
natural gas to large commercial and industrial customers in South Carolina, and
it faces the same competitive pressures as gas distribution for these classes of
customers.
Retail Gas Marketing
In April 2002 Georgia's Natural Gas Consumer's Relief Act of 2002 (the
Act) became law. The Act attempts to resolve many of the consumer protection and
other public policy issues surrounding Georgia's natural gas market with the
following significant provisions:
o creates a regulated provider selected through a bidding process to serve
low-income and high credit risk customers, o allows Georgia's 42 non-profit
Electric Membership Corporations (EMCs) to establish natural gas affiliates that
may seek
certification as marketers of natural gas,
o establishes new service quality standards and assignment of interstate
assets, and
o grants to the GPSC the authority to temporarily regulate rates if more
than 90% of customers in a specific area of the state are served by
three or fewer marketers.
In June 2002 SCANA Energy won GPSC approval to become the State's
regulated provider. In this capacity, SCANA Energy serves low-income customers
generally at below-market rates, subsidized by Georgia's Universal Service Fund,
and extends service generally at above-market rates to high credit risk
customers who have been denied service by other marketers. SCANA Energy began
serving these customers on September 1, 2002, and at December 31, 2002,
approximately 11,000 customers were being served by SCANA Energy under this
program.
In June 2002 the fourth largest marketer in Georgia's natural gas market
declared bankruptcy. In July 2002 a subsidiary of Southern Company completed its
purchase of the bankrupt marketer's Georgia operations. Southern Company,
through another subsidiary, sells electricity to approximately two million
customers in Georgia. In addition, affiliates of two EMCs have been certified by
the GPSC as gas marketers. These new entrants to Georgia's natural gas market
may help stabilize the market, although it is unclear what impact these entrants
may have on the Company's competitive position. At December 31, 2002 the three
largest marketers (which include SCANA Energy) served approximately 80% of
Georgia's natural gas 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 and options, to manage
their exposure to fluctuating commodity natural gas prices. (See Note 11 of
Notes to Consolidated Financial Statements.) As a part of this risk management
process, at any given time a portion of SCANA's projected natural gas needs has
been purchased or otherwise placed under contract. 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 regulatory actions
discussed above and other downward pricing pressures inherent in the competitive
market, SCANA Energy may be unable to sustain its current level 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 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.
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
The estimated primary cash requirements for 2003 and the actual primary
cash requirements for 2002, excluding requirements for non-nuclear fuel
purchases, short-term borrowings and dividends, are as follows:
Millions of dollars 2003 2002
- ------------------------------------------------------------- -------------
Property additions and construction
expenditures, net of AFC $838 $681
Nuclear fuel expenditures 30 13
Investments 20 62
Maturing obligations, redemptions and
sinking and purchase fund requirements 374 1,082
- ------------------------------------------------------------- -------------
Total $1,262 $1,838
============================================================= =============
Approximately 28% of total cash requirements was provided from internal
sources in 2002 as compared to 41% in 2001.
The Company's contractual cash obligations as of December 31, 2002 are
summarized as follows:
Contractual Cash Obligations
Less than After
December 31, 2002 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of dollars)
Long-term and short-term debt
(including interest) $5,215 $759 $1,048 $409 $2,999
Preferred stock sinking funds 10 1 2 1 6
Capital leases 3 2 1 - -
Operating leases 76 16 33 19
8
Other commercial commitments 2,518 1,249 571 173 525
Included in other commercial commitments are estimated obligations under
forward contracts for natural gas purchases. Many of these forward contracts for
natural gas purchases include customary "make-whole" or default provisions, but
are not considered to be "take-or-pay" contracts. Certain of these contracts
relate to regulated businesses; therefore, the effects of such contracts on fuel
costs are reflected in electric or gas rates. At September 30, 2002, other
commercial commitments included amounts for a take-and-pay natural gas contract
with a 15 year term beginning in 2004. That contract was terminated in December
2002, and amounts due under the contract totaling $4.2 billion over the 15 year
term have been removed from contractual cash obligations. See Note 12E of Notes
to Consolidated Financial Statements.
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 through December 31, 2002 are funded in cash. These
derivatives are accounted for as cash flow hedges under SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended, and their
effects are reflected within other comprehensive income until such time as the
anticipated sales transactions occur.
In addition to the above contractual cash commitments, the Company
sponsors a noncontributory defined benefit pension plan and an unfunded health
care and life insurance benefit plan for retirees. The pension plan has been
adequately funded, with no contributions having been required since 1997. Cash
benefit payments under the health care and life insurance benefit plan have been
approximately $10 million per year in recent years, and similar payments are
expected in the future.
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 and the
SEC. The following describes 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, 2002 SCANA had $163 million of unused lines of credit,
comprised of $50 million of committed lines, expiring in 2003, and $113 million
of uncommitted lines. There were no amounts outstanding under SCANA's lines of
credit at December 31, 2002 and 2001. On January 3, 2003 SCANA obtained an
additional $50 million committed line of credit, expiring in 2004. On January 8,
2003, SCANA renegotiated an existing $78 million uncommitted line of credit to
allow SCE&G to share in this line of credit.
The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable and receive
fixed interest payments, and are designated as fair value hedges of certain debt
instruments. The Company may terminate a swap agreement, and may replace it with
a new swap also designated as a fair value hedge.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.
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, 2002 the Bond Ratio
was 5.51. The Old Mortgage allows the issuance of Class A Bonds up to an
additional principal amount equal to (i) 70% of unfunded net property additions
(which unfunded net property additions totaled approximately $522 million at
December 31, 2002), (ii) retirements of Class A Bonds (which retirement credits
totaled $187.2 million at December 31, 2002), 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. At December 31, 2002 approximately $1.3 billion Class A Bonds were
on deposit with the Trustee of the New Mortgage and are available to support the
issuance of additional New Bonds. 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, 2002 the New Bond Ratio was 5.36.
SCE&G's Restated Articles of Incorporation (the Articles) 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, 2002, the Preferred Stock Ratio was 1.72.
The Articles also require the consent of at least a majority of the total
voting power of SCE&G's preferred stock before SCE&G may issue or assume any
unsecured indebtedness if, after such issue or assumption, the total principal
amount of all such unsecured indebtedness would exceed ten percent of the
aggregate principal amount of all of SCE&G's secured indebtedness and capital
and surplus (the ten percent test). No such consent is required to enter into
agreements for payment of principal, interest and premium for securities issued
for pollution control purposes. At December 31, 2002 the ten percent test would
have limited issuances of unsecured indebtedness to approximately $366.7
million. Unsecured indebtedness at December 31, 2002 totaled approximately
$127.6 million.
At December 31, 2002 SCE&G had $250 million of unused committed lines of
credit comprised of $175 million expiring in 2003 and $75 million expiring in
2005. These lines of credit support the issuance of commercial paper. SCE&G's
commercial paper outstanding totaled $127.6 million and $114.7 million at
December 31, 2002 and 2001, respectively, at weighted average interest rates of
1.40% and 1.95%, respectively. On January 8, 2003 a credit agreement was reached
allowing SCE&G to share an existing $78 million SCANA uncommitted line of
credit. In addition, Fuel Company has a credit agreement for a maximum of $125
million expiring in 2003 with the full amount available at December 31, 2002.
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 totaled $50.1 million at
December 31, 2002 and 2001, at weighted average interest rates of 1.38% and
2.06%, 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 Energy 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. PSNC Energy expects that it has or can obtain adequate sources of
financing to meet its projected cash requirements for the foreseeable future.
At December 31, 2002 PSNC Energy had $125 million unused committed lines
of credit, expiring in 2003, under a credit agreement supporting the issuance of
commercial paper. PSNC Energy had total commercial paper outstanding of $31.1
million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC
Energy had no commercial paper outstanding at December 31, 2001.
Financing Transactions
The following financing transactions have occurred since January 1, 2002:
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%. Also
on January 31, 2002 SCANA issued $150 million of two-year floating rate
notes maturing 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 February 8, 2002, which had
been issued to finance SCANA's acquisition of PSNC Energy.
o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds
having an annual interest rate of 6.625% 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 on March 11, 2002 its $103.5 million First and Refunding Mortgage
Bonds, 8 7/8% Series due August 15, 2021.
o On April 24, 2002 SCANA redeemed $202 million of floating rate medium-term
notes that were set to mature January 24, 2003. The notes were bearing
interest at a rate of 2.90% when redeemed.
o On July 15, 2002 SCANA retired at maturity $300 million of floating rate
medium-term notes. The notes were bearing interest at a rate of 4.063% at
maturity.
o On August 15, 2002 SCANA issued $100 million one-year floating rate
medium-term notes maturing August 15, 2003. The interest rate on the notes
is reset quarterly based on three-month LIBOR plus 87.5 basis points. The
proceeds were used for general corporate purposes.
o On October 16, 2002 SCANA sold 6 million shares of common stock and
received net proceeds of approximately $146 million. On October 17, 2002
SCANA made an equity contribution to SCE&G of $150 million.
o On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and SCE&G borrowed the proceeds of, an aggregate
of $90.4 million principal amount of tax exempt industrial revenue bonds
(the Bonds). The Bonds bear interest at rates ranging from 4.2% to 5.45%,
with maturities ranging from 2012 to 2032. Proceeds from the Bonds were
used to refund an aggregate amount of $62.3 million principal amount of
pollution control revenue bonds and to pay the costs of solid waste
disposal facilities at two of SCE&G's electric generating plants.
o On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having
an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt
and for general corporate purposes.
o The Company received payments to terminate swaps totaling $29.3 million
and $6.5 million in 2002 and 2001, respectively. These amounts are being
amortized over the ten year term of the underlying debt they formerly
hedged. At December 31, 2002 the estimated fair value of the Company's
swaps totaled $9.0 million related to combined notional amounts of $344.9
million.
Other Information
SCE&G placed in service a $264 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 341 MW of new electric generation and use exhaust heat to
replace coal-fired steam that powers two existing 75 MW turbines at the Urquhart
Generating Station.
In May 2002 SCE&G began construction of an 875 MW 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. The $450 million facility is
expected to begin commercial operation in mid-2004. SCG will transport natural
gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in
order to comply with new federal safety standards and 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 approximately $275
million and be completed in 2005. Costs incurred through December 31, 2002
totaled approximately $67 million.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the above Lake Murray dam
remediation project. The loan agreement provides for interest-free borrowings
for costs incurred not to exceed $59 million, with such borrowings being repaid
over ten years from the initial borrowing. At December 31, 2002 SCE&G had not
yet borrowed under the agreement.
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 remains in compliance with these requirements. In
1998 the EPA required the State of South Carolina, among other states, to modify
its state implementation plan (SIP) to address the issue of NOx pollution. The
State's SIP requires additional emissions reductions in 2004 and beyond.
Further, 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. To comply with these state and federal regulations, SCE&G and
GENCO expect to incur capital expenditures of approximately $131 million over
the 2003-2007 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 2008 through 2012, the Company anticipates additional
capital expenditures of approximately $125 million.
The EPA has undertaken an aggressive enforcement initiative against the
utilities 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 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 of
monitoring and controlling thermal discharges and strategies for toxicity
reduction in wastewater streams. The Company is developing compliance plans for
these initiatives. Congress is expected to consider further amendments to the
Clean Water Act in 2003. Such legislation may include limitations to mixing
zones, the implementation of technology-based standards for main condenser
cooling water including intake and discharge structures and toxicity-based
standards. These provisions, if passed, could have a material impact on the
results of operations and cash flows of SCE&G and GENCO.
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 solely to regulated operations and are recorded in deferred
debits and amortized with recovery provided through rates. Deferred amounts for
SCE&G, net of amounts previously recovered through rates and insurance
settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and
2001, respectively. The deferral includes the estimated costs associated with
the following matters.
o SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for
benzene contamination in the intermediate aquifer on surrounding
properties. SCE&G anticipates that the remaining remediation activities
will be completed in 2003, with certain monitoring and retreatment
activities continuing until 2007. As of December 31, 2002, SCE&G has
spent approximately $18.4 million to remediate the Calhoun Park 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
before 2006. SCE&G has spent approximately $2.2 million related to these
sites, and expects to incur an additional $5.9 million.
In addition, PSNC Energy 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 Energy's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
PRPs. In September 2002 an allocation agreement was reached relieving PSNC
Energy of liability for two of the seven sites. PSNC Energy has recorded a
liability and associated regulatory asset of $7.8 million, which reflects the
estimated remaining liability at December 31, 2002. Amounts incurred to date
that have not been recovered through gas rates are approximately $1.2 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
$296 million and $114 million of regulatory assets and liabilities,
respectively, including amounts recorded for deferred income tax assets and
liabilities of approximately $137 million and $43 million, respectively, on its
balance sheet at December 31, 2002.
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, 2002 the Company's net investment in fossil and hydro and nuclear
generation assets was approximately $1,921 million and $546 million,
respectively.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
On December 31, 2002 the SCPSC issued an order approving SCE&G's request
to capitalize the cost of fuel consumed in the production of test power for the
gas turbines installed at Urquhart Generating Station in 2002. As a result,
SCE&G transferred approximately $12.5 million from fuel used in electric
generation to electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request
to increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for 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 2002. In January 2003 in
conjunction with the approval of the retail rate increase, the SCPSC approved
SCE&G's request to reduce the fuel component to 1.678 cents per KWh.
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, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001
$.728 November-December 2002 $.793 March-October 2001
$.596 November-December 2001
In March 2003 the SCPSC issued an order approving SCE&G's request for an
out-of-period adjustment to increase the cost of gas component of its rates for
natural gas service from $.728 per therm to $.928 per therm, effective with the
first billing cycle in March 2003.
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 2002, as a
result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of
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, 2002 of $17.9
million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over eight years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City.
SCE&G will continue to operate the plant for the City until 2005. SCE&G will
also pay the Central Midlands Regional Transit Authority up to $3 million as
matching funds for Federal Transit Administration grants for the purchase of new
transit coaches and a new transit facility. The cost of the franchise agreement
is recorded in other regulatory assets.
Public Service Company of North Carolina, Incorporated
PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates,
issuance of securities (other than notes with a maturity of two years or less or
renewals of notes with a maturity of six years or less), accounting and other
matters.
PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the deferred cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually.
PSNC Energy's benchmark cost of gas in effect during the years ended
December 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001
$.215 February-June 2002 $.750 February-March 2001
$.350 July-October 2002 $.650 April-August 2001
$.410 November-December 2002 $.500 September-October 2001
$.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase
the benchmark cost of gas from $.410 to $.460 per therm effective for service
rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC
Energy's request to increase the benchmark cost of gas from $.460 to $.595 per
therm effective March 1, 2003.
In April 2000 the NCUC issued an order permanently approving PSNC
Energy'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 Energy 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 Energy's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC
Energy's requests for disbursement of up to $28.4 million from PSNC Energy's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties in western North Carolina. PSNC Energy estimates that the cost of this
project will be approximately $31.4 million. The Madison County and Jackson
County portions of the project were completed by the end of 2002. At December
31, 2002 approximately $16.9 million had been spent on this project. The unused
portion of PSNC Energy's expansion fund is recorded in prepaid assets.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC Energy. As specified in the order, PSNC Energy 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.
South Carolina Pipeline Corporation
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an August 2002 order, the SCPSC
found that for the period January 2001 through March 2002 SCPC's gas purchasing
policies and practices were prudent and that SCPC properly adhered to the gas
cost recovery provisions of its gas tariff.
REGULATORY MATTERS - FEDERAL
SCANA is 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. A customary three-year renewal of the Company's financing and other
authorizations under PUHCA was received on February 12, 2003.
The Company's regulated business operations were impacted by FERC Order
No. 2000 and other related initiatives of the FERC. Order No. 2000 required each
utility under FERC jurisdiction that operates an electric transmission system to
submit plans for the possible formation of a regional transmission organization.
In March 2001 FERC gave provisional approval to SCE&G and two other southeastern
electric utilities to establish GridSouth as an independent regional
transmission company, responsible for operating and planning the utilities'
combined transmission systems. In June 2002 GridSouth implementation was
suspended pending the issuance and evaluation of new FERC directives.
In July 2002 FERC issued a NOPR on Standard Market Design which proposes
sweeping changes to the country's existing regulatory framework governing
transmission, open access and energy markets and which will attempt, in large
measure, to standardize the national energy market. While it is anticipated that
significant changes to the NOPR may occur and that implementation, presently
scheduled for September 2004, may not occur for some time, any rules
standardizing the markets may have significant impact on the Company's access to
or cost of power for its native load customers and on the Company's marketing of
power outside its service territory. The Company is currently evaluating this
NOPR to determine what effect it will have on its operations. Additional
directives from FERC are expected later in 2003.
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 financial condition or results of
operations.
SFAS 71- The Company's regulated utilities are subject to the provisions
of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," which
require them to record certain assets and liabilities that defer the recognition
of expenses and revenues to future periods as a result of being rate-regulated.
At December 31, 2002 the Company had recorded approximately $296 million and
$114 million of regulatory assets and liabilities, respectively, including
amounts recorded for deferred income tax assets and liabilities. Management
believes the regulatory assets are recoverable through rates. The state
commissions which regulate the utilities 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 state commissions. 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
state commission approval. In the future, as a result of deregulation or other
changes in the regulatory environment, the Company may no longer meet the
criteria for continued application of SFAS 71 and could be required to write off
its regulatory assets and liabilities. Such an event could have a material
adverse effect on the results of operations of the Company's Electric
Distribution and Gas Distribution segments in the period the write-off would be
recorded. It is not expected that cash flows or financial position would be
materially affected.
Certain of the Company's regulatory assets and liabilities arise from
its environmental assessment program, which identifies and evaluates 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. Regulatory
assets and liabilities related to environmental cleanup affect primarily the Gas
Distribution segment and are due to the costs associated with current and former
MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale
of energy are recorded when service is rendered or when energy is delivered to
customers. Because customers of our utilities and retail gas operations are
billed on cycles which vary based on the timing of the actual reading of their
electric and gas meters, we record estimates for unbilled revenues at the end of
each reporting period. Such unbilled revenue amounts reflect estimates of the
amount of energy delivered to each customer since the date of the last reading
of their respective meters. Such unbilled revenues reflect consideration of
estimated usage by customer class, the effects of different rate schedules,
changes in weather and, where applicable, the impact of weather normalization
provisions of rate structures. The accrual of unbilled revenues in this manner
properly matches revenues and related costs. As of December 31, 2002 and 2001,
accounts receivable include unbilled revenues of $107.7 million and $81.1
million, respectively. Total revenues for 2002 and 2001 were $2.95 billion and
$3.45 billion, respectively.
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 is
depreciated as a component of plant cost in establishing rates for utility
services. The Company's regulated subsidiaries calculated AFC using composite
rates of 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, 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. AFC primarily affects the Electric Operations segment due to its
capital-intensive construction program, and to a lesser extent, AFC affects the
Gas Distribution and Gas Transmission segments. AFC represented approximately
9.1% of income before income taxes, gains, losses, impairments and the
cumulative effect of an accounting change in 2002, 7.2% in 2001 and 2.3% in
2000. Because the equity component of AFC is not taxable, increased AFC reduces
the Company's effective tax rate. See Results of Operations for additional
discussion.
Provisions for Bad Debts and Allowances for Doubtful Accounts - As of
each balance sheet date, the Company evaluates the collectibility of accounts
receivable and records allowances for doubtful accounts based on estimates of
the level of 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. The distribution segments of the
Company's regulated utilities have an established write-off history, and the
regulated service areas enable the utilities to reliably estimate their
respective provision for bad debts. The Company's Retail Gas Marketing segment
operates in Georgia's natural gas market. As such, estimation of the provision
for bad debts related to this segment is subject to greater imprecision. In
2002, the Retail Gas Marketing segment expensed approximately $6.2 million
related to bad debt, which represents approximately 1.6% of its gross revenue.
Had an additional 1% of gross revenues been reserved for bad debts, net income
in 2002 would have been reduced by approximately $2.4 million.
Nuclear Decommissioning - Accounting for decommissioning costs for
nuclear power plants involves significant estimates related to costs to be
incurred many years in the future. Among the factors that could change SCE&G's
accounting estimates related to decommissioning costs are changes in technology,
changes in regulatory and environmental remediation requirements, as well as
changes in financial assumptions such as discount rates and timing of cash
flows. See also the discussion of the Company's adoption of SFAS 143,
"Accounting for Asset Retirement Obligations," below. Changes in any of these
estimates could significantly impact the Company's financial position and cash
flows (although changes in such estimates should be earnings-neutral, because
these costs are expected to be collected from ratepayers).
SCE&G's 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 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 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
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. Management
intends for the fund, including earnings thereon, to provide for all eventual
decommissioning expenditures on an after-tax basis.
Pension Accounting - SCANA follows SFAS 87, "Employers Accounting for
Pensions," in accounting for its defined benefit pension plan. SCANA's plan is
fully funded and as such, net pension income is reflected in the financial
statements (see Results of Operations). SFAS 87 requires the use of several
assumptions, the selection of which may have a large impact on the resulting
benefit recorded. Among the more sensitive assumptions are those surrounding
discount rates and returns on assets. Net pension income of $25.8 million
recorded in 2002 reflects the use of a 7.5% discount rate and an assumed 9.5%
long-term return on plan assets. SCANA believes that these assumptions were, and
that the resulting pension income amount was, reasonable.
Due to poor performance in the stock market in recent years, the Company
has determined to adjust its assumed long-term return on assets to 9.25% for
2003. Lower interest rates have also led to a reduction in the discount rate as
of December 31, 2002 to 6.5%. Had those assumptions been in place in 2002, net
pension income would have been reduced by approximately $5.3 million.
In determining the appropriate discount rate, the Company considers the
market indices of high-quality long-term fixed income securities. As such, the
Company selected the above discount rate of 6.5% as being within a reasonable
range of Moody's "Aa" interest rate as of December 31, 2002. This same discount
rate was also selected for determination of OPEB liabilities discussed below.
The following information with respect to pension assets should also be
noted:
The Company determines the fair value of substantially all of its
pension assets utilizing market quotes rather than utilizing any calculated
values, "market related" values or other modeling techniques. In developing the
expected long-term rate of return assumptions, the Company evaluated input from
actuaries and from pension fund investment advisors, including such advisors'
review of the plan's historical 10, 16 and 24 year cumulative actual returns of
10.15%, 10.80% and 12.32%, respectively, which have all been in excess of
related broad indices. The Company anticipates that investment managers will
continue to generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset
allocation of 80% with equity managers and 20% with fixed income managers. While
management believes that the asset allocation will return to those levels,
because of market fluctuations, the actual asset allocation as of December 31,
2002 was 70% with equity managers and 30% with fixed income managers. Management
regularly reviews such allocations and periodically rebalances the portfolio to
the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate
have significantly reduced the level of pension income, the pension trust has
been and remains adequately funded, and no contributions have been required
since 1997. As such, recent declines in pension income have had no impact on the
Company's cash flows. Based on stress testing performed by the Company's
actuaries, management does not anticipate the need to make pension contributions
until at least 2008.
Accounting for Postretirement Benefits other than Pensions - Similar to
its pension accounting, SCANA follows SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," in accounting for its
postretirement medical and life insurance benefits. This plan is unfunded, so no
assumptions related to return on assets impact the net expense recorded;
however, the selection of discount rates can significantly impact the actuarial
determination of net expense. SCANA used a discount rate of 7.5% and recorded a
net SFAS 106 cost of $18.3 million for 2002. Had the selected discount rate been
6.5%, the expense for 2002 would have been approximately $1.2 million higher.
SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and
Other Intangible Assets," the Company performed a valuation analysis of its
investment in SCPC (Gas Transmission segment) using a discounted cash flow
analysis and of PSNC Energy (Gas Distribution segment) using an independent
appraisal. The analysis for SCPC indicated that the fair value of related
goodwill exceeded its carrying amount. The independent appraisal made various
assumptions related to cash flow projections, discount rates, weighted average
cost of capital and market multiples for comparable companies. The analysis
indicated that the carrying amount of PSNC Energy's acquisition adjustment
(goodwill) exceeded its fair value, and as a result, the Company recorded an
impairment charge of $230 million as the cumulative effect of an accounting
change, effective January 1, 2002. SFAS 142 requires the Company to perform
valuation analyses annually. Such analyses will incorporate updated assumptions
similar to those used for the initial valuations.
SFAS 143 - SFAS 143 provides guidance for recording and disclosing
liabilities related to the future obligations to retire assets (ARO). SFAS 143
applies to the legal obligation associated with the retirement of long-lived
tangible assets that result from acquisition, construction, development and
normal operations. The Company adopted SFAS 143 effective January 1, 2003.
Because such obligation relates solely to the Company's regulated electric
utility, adoption of SFAS 143 will have no impact on results of operations;
however, the Company will record an ARO of approximately $110 million, which
exceeds the previously recorded reserve for nuclear plant decommissioning of
approximately $87 million.
In addition to the ARO for Summer Station, the Company believes that
there is legal uncertainty as to the existence of environmental obligations
associated with certain transmission and distribution properties. The Company
believes that any ARO related to this type of property would be insignificant
and, due to the indeterminate life of the related assets, an ARO could not be
reasonably estimated.
The Company's regulated operations record cost of removal as a component
of accumulated depreciation for property that does not have an associated legal
retirement obligation. As of December 31, 2002, the Company estimates that
approximately $325 million of its accumulated depreciation balance is related to
this regulatory liability.
OTHER MATTERS
Unconsolidated Special Purpose Entities
Although SCANA invests in securities and business ventures, it does not
hold investments in unconsolidated special purpose entities such as those
described in SFAS 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities," 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.
Synthetic Fuel Investments
SCE&G holds two equity-method investments in partnerships involved in
converting coal to non-conventional fuel, the use of which fuel qualifies for
federal income tax credits. The aggregate investment in these partnerships as of
December 31, 2002 is approximately $2 million, and through December 31, 2002,
they had generated and passed through to SCE&G approximately $58 million in such
tax credits. Under a plan approved by the SCPSC, any tax credits generated and
ultimately passed through to SCE&G from synfuel produced and consumed by SCE&G
have been and will be deferred and will be applied to offset the capital costs
of projects required to comply with legislative or regulatory actions. See Note
1B of Notes to Consolidated Financial Statements.
Nuclear License Extension
In August 2002 SCE&G filed an application with the NRC for a 20-year
license extension for its Summer Station. If approved, the extension would allow
the plant to operate through 2042. SCE&G estimates that it will incur
approximately $12 million in costs related to the application process.
Radio Service Network
In April 2002 SCI sold its 800 Mhz radio service network within South
Carolina to Motorola, Inc.
Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets
of SCANA filed suit against SCANA in South Carolina 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.
In 2001 the Company entered into, in the ordinary course of business, a
15 year take-and-pay contract with an unaffiliated natural gas supplier
(Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring
of 2004. In December 2002, as a result of the failure of Supplier and its
guarantor to meet contractual obligations related to credit support provisions,
the Company terminated the contract. Attempts to negotiate a new contract
between the parties were not successful. In February 2003, the Company received
notification from Supplier of its request for binding arbitration under the
original contract. The Company is confident of the propriety of its actions and
will vigorously pursue its position in such arbitration proceedings. The Company
further believes that the resolution of these claims will not have a material
adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
Telecommunications Investments
At December 31, 2002 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 following table.
Investee Securities Basis
- --------------- ------------------------------------------------ ---------------
(Millions of dollars)
ITC Holding 3.1 million shares common stock $5.8
645,153 shares series A preferred stock, convertible
into
2.6 million shares of common stock 7.2
133,664 shares series B preferred stock, convertible
into
534,656 shares of common stock 4.0
ITC^DeltaCom 566,010 shares of common stock 1.1
149,077 shares series A 8% preferred stock,
convertible in 2005 into 2.6 million shares of
common stock 12.7
Warrants to purchase 506,861.8 shares of common stock 1.1
Knology 7.2 million shares series A preferred stock,
convertible into
7.5 million shares of common stock 14.1
14.8 million shares series C preferred stock,
convertible into
14.8 million shares of common stock 35.1
21.7 million shares series E preferred stock,
convertible
into 21.7 million shares of common stock 40.6
$43.6 million face amount, 12% senior unsecured
notes due 2009, including accrued interest 43.6
In 2002 SCH sold the 39.3 million shares it held in DTAG through a
series of market transactions. See additional information at Results of
Operations.
ITC Holding Company (ITC Holding) holds ownership interests in several
Southeastern communications companies. As these securities are not actively
traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc.
(ITC^DeltaCom) is a regional provider of telecommunications services. Knology,
Inc. (Knology) is a broadband service provider of cable television, telephone
and internet services.
In June 2002 ITC^DeltaCom announced plans for a reorganization and
entered into Chapter 11 bankruptcy. As a result the Company wrote off its
investments in ITC^DeltaCom in the second quarter and recorded an aggregate
impairment charge of approximately $7.0 million (after tax). The bankruptcy
court accepted the reorganization plan, and ITC^DeltaCom emerged from bankruptcy
on October 29, 2002. In connection with ITC^DeltaCom's emergence from
bankruptcy, SCH provided $14.9 million in preferred equity financing. The common
shares owned by SCH have a market value of $1.3 million, thus an unrealized gain
of $0.2 million has been recorded in Other Comprehensive Income. The preferred
shares owned by SCH are classified as held to maturity due to their debt
features, and the market value is not readily determinable.
In July 2002 Knology negotiated a potential exchange of its Knology
Broadband discount notes for a combination of new notes and new preferred stock.
In contemplation of the anticipated exchange, the Company recorded an impairment
loss of approximately $0.3 million (after-tax) in the second quarter. Because
the exchange offer did not result in the requisite minimum tender of notes, in
the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which
reflected the same terms of exchange. The bankruptcy court accepted the
reorganization plan, and in connection with Knology's emergence from bankruptcy,
SCH purchased an additional 6.5 million shares of series C preferred stock for
approximately $19.5 million. The market value of Knology securities as of
December 31, 2002 is not readily determinable.
RESULTS OF OPERATIONS
Earnings (Loss) and Dividends
Earnings (loss) per share of common stock and cash dividends declared
for 2002, 2001 and 2000 were as follows:
2002 2001 2000
-----------------------------------------------------------------------------
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Earnings (loss) derived from:
Continuing operations $2.38 $2.15 $2.12
Gains from sales of investments and assets .24 3.42 -
Investment impairments (1.79) (.42) -
Cumulative effects of accounting changes, net of taxes (2.17) - .28
------------------------------------------------------------------------------
Earnings (loss) per weighted average share $(1.34) $5.15 $2.40
==============================================================================
Cash dividends declared (per share) $1.30 $1.20 $1.15
===============================================================================
o 2002 vs 2001 Earnings derived from continuing operations increased $.23
primarily due to improved margins from sales of electricity of $.36, lower
interest expense of $.14, improved results from non-regulated subsidiaries
of $.08, increased allowance for funds used during construction of $.06,
lower depreciation and amortization expense of $.02 and other items
totaling $.03. These factors were partially offset by higher operations and
maintenance expense of $.24 (including $.07 due to lower pension income),
lower gas margins of $.15 and higher property taxes of $.07.
o 2001 vs 2000 Earnings derived from continuing operations increased $.03,
primarily as a result of improved results from retail gas marketing of
$.03, improved results from energy marketing of $.09, completion of repairs
at Summer Station in 2000 of $.04, the elimination of the imputed interest
expense related to the PSNC Energy acquisition in 2000 of $.05 and other
items totaling $.02. These improvements were partially offset by a decrease
in electric margin of $.11 and a decrease in regulated gas margin of $.09.
In 2002 the Company recorded an impairment charge of $1.72 per share
related to the other than temporary decline in market value of the Company's
investment in DTAG. In addition, the Company recorded an impairment charge of
$.07 per share related to the other than temporary decline in market value of
its investment in ITC^DeltaCom (see Note 11 of Notes to Consolidated Financial
Statements). Also, as required by SFAS 142 the Company recorded as the
cumulative effect of an accounting change an impairment charge of $2.17 per
share related to the acquisition adjustment associated with PSNC Energy (see
Note 1G of Notes to Consolidated Financial Statements). In addition, the Company
recognized gains of $.09 per share from the sale of the Company's radio service
network and $.15 per share in connection with its sale of DTAG shares.
In 2001 the Company recognized a gain of $3.38 per share in connection
with the exchange 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. The Company also
recorded impairment charges related to investments in ITC^DeltaCom of $.34 per
share, a developer of micro-turbine technology of $.04 per share and a lime
production plant of $.04 per share.
In 2000 the cumulative effect of an accounting change resulted from the
initial recording of unbilled revenues by SCANA's retail utility subsidiaries
(see Note 2 of Notes to Consolidated Financial Statements).
Pension Income
For the last several years, the market value of the Company's
retirement plan (pension) assets has exceeded the total actuarial present value
of accumulated plan benefits. However, pension income for 2002 decreased
significantly compared to 2001 and 2000, primarily as a result of a less
favorable investment market. Pension income during these periods, excluding
amounts attributable to Santee Cooper (see Note 5), was recorded on the
Company's financial statements as follows:
Millions of dollars 2002 2001 2000
- --------------------------------------------------- ----------------------
- --------------------------------------------------- ----------------------
Income Statement Impact:
Reduction in employee benefit costs $10.9 $22.6 $22.6
Increase in other income 11.1 12.7 12.8
Balance Sheet Impact:
Reduction in capital expenditures 3.1 6.2 5.8
Increase in amount due to Santee Cooper .7 1.8 2.0
- --------------------------------------------------- ----------------------
- --------------------------------------------------- ----------------------
Total Pension Income $25.8 $43.3 $43.2
=================================================== ======================
See also the discussion of pension accounting in Critical Accounting Policies
and New Accounting Standards.
Allowance for Funds Used During Construction (AFC)
The Company's financial statements include the effects of the recording
of 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 9.1% of
income before income taxes, gains, losses, impairments and the cumulative effect
of an accounting change in 2002, 7.2% in 2001 and 2.3% in 2000.
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 2002, 2001 and 2000, excluding the cumulative
effect of accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000
- --------------------------------------------- ---------------- ---------------
Operating revenues $1,379.5 $1,368.7 $1,343.8
Less: Fuel used in generation (329.6) (283.3) (294.9)
Purchased power (42.1) (138.1) (82.5)
- --------------------------------------------- ---------------- ---------------
Margin $1,007.8 $947.3 $966.4
============================================= ================ ===============
o 2002 vs 2001 Margin increased $31.9 million due to more favorable weather
and $30.5 million due to customer growth. Fuel used in generation increased
and purchased power decreased due to completion of the Urquhart Station
repowering project in June 2002 and fewer plant outages during 2002.
o 2001 vs 2000 Sales margin decreased $32.1 million due to milder weather and
$12.6 million due to the impact of the slowing economy. These decreases
were partially offset by $25.6 million from customer growth.
Increases (decreases) from the prior year in MWh sales volume by classes
were as follows:
Classification (in thousands) 2002 % Change 2001 % Change
- ------------------------------------------------------------- ------------
Residential 735.6 11.3% (170.5) (2.5%)
Commercial 370.5 5.9% (16.8) -
Industrial 158.0 2.5% (317.7) (4.8%)
Sales for resale
(excluding interchange) 333.7 29.9% (108.3) (8.8%)
Other 1.1 0.2% (18.9) (3.4%)
- ----------------------------------------- -----------
Total territorial 1,598.9 7.7% (632.2) (3.0%)
NMST (1,441.7) (67.1%) 208.0 10.0%
- ----------------------------------------- -----------
Total 157.2 0.7% (424.2) (2.0%)
============================================================= ============
o 2002 vs 2001 Territorial sales volume increased primarily due to more
favorable weather. The decrease in NMST volumes reflects
the Company's recording of buy-resale transactions in Other
Income in 2002.
o 2001 vs 2000 Territorial sales volume decreased primarily due to milder
weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC Energy. Gas distribution sales margins (including transactions
with affiliates) for 2002, 2001 and 2000, excluding the cumulative effect of
accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000
- ------------------------------------------- ------------- -------------
Operating revenues $653.9 $793.6 $745.9
Less: Gas purchased for resale (401.0) (537.8) (486.3)
- ------------------------------------------- ------------- -------------
Margin $252.9 $255.8 $259.6
=========================================== ============= =============
Sales margin decreased slightly over the three year period primarily as a
result of the slowing economy and increased competition with alternate fuels.
Increases (decreases) from the prior year in DT sales volume by classes,
including transportation gas, were as follows:
Classification (in thousands) 2002 % Change 2001 % Change
- ----------------------------------------- ------------------------- ------------
Residential 3,707.2 11.6% (7,068.1) (18.1%)
Commercial 1,344.2 5.7% (2,613.2) (10.0%)
Industrial 1,668.4 8.5% (2,860.0) (12.7%)
Transportation gas 1,986.2 7.0% (3,318.6) (10.5%)
Sales for resale 0.1 6.1% 1.0 *
- ----------------------------------------- --------------
Total 8,706.1 8.4% (15,858.9) (13.3%)
========================================= ========================= ============
*Not meaningful
o 2002 vs 2001 Residential and commercial sales volume increased
primarily due to more favorable weather. Industrial and
transportation gas volumes increased in 2002 after the
volatility of the natural gas market in 2001 had resulted
in interruptible customers using their alternate fuel
sources during that year.
o 2001 vs 2000 Residential sales volume decreased due to
higher gas prices. Industrial and transportation gas
decreased due to the volatility of the natural gas market
resulting in interruptible customers using alternate fuel
sources.
Gas Transmission
Gas Transmission is comprised of the operations of SCPC. Gas transmission
sales margins (including transactions with affiliates) for 2002, 2001 and 2000
were as follows:
Millions of dollars 2002 2001 2000
- --------------------------------------------- ------------- -------------
Operating revenues $479.1 $478.0 $489.0
Less: Gas purchased for resale (442.4) (434.1) (434.7)
- --------------------------------------------- ------------- -------------
Margin $36.7 $43.9 $54.3
============================================= ============= =============
o 2002 vs 2001 Sales margin decreased $9.6 million due to the unfavorable
competitive position of natural gas relative to alternate fuels in the
first quarter, which was partially offset by a favorable competitive
position in the remaining quarters of $1.4 million and increased sales for
electric generation of $1.0 million.
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 of $8.5 million, decreased volume of
sales to electric generation due to milder weather of $1.4 million and
reduced margins in sales for resale as a result of milder weather of $0.5
million.
Increases (decreases) from the prior year in DT sales volume by classes
including transportation were as follows:
Classification (in thousands) 2002 % Change 2001 % Change
------------------------------------- --------------------------------------
Commercial 46.1 64.5% (42.2) (37.2%)
Industrial 17,402.5 59.6% (10,127.6) (25.8%)
Transportation 770.2 25.8% 725.1 32.1%
Sales for resale 4,299.7 8.2% (9,529.6) (15.3%)
------------------------------------- ----------------
Total 22,518.5 26.5% (18,974.3) (18.3%)
===================================== ======================================
o 2002 vs 2001 Industrial volumes increased 3,732.2 thousand DTs due to
increased electric generation and 4,395.8 thousand DTs due to the emergence
from bankruptcy of a large industrial customer. The remaining increase is
primarily due to improved competition with alternate fuels. Sales for
resale volumes increased due to more favorable weather.
o 2001 vs 2000 Commercial and industrial volumes decreased primarily due to
increased gas to gas competition. Transportation volumes increased due to
increased gas to gas competition. Sales for resale volumes decreased due to
milder weather.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail
Gas Marketing revenues and net income for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000
------------------------------------ --------------- ----------------
Operating revenues $379.5 $453.8 $412.8
Net income 14.3 6.8 3.2
------------------------------------ --------------- ----------------
o 2002 vs 2001 Operating revenues decreased primarily as a result of lower
average retail prices and lower volumes. Net income increased primarily due
to lower bad debt expense of $8.1 million, lower interest and depreciation
expense of $1.6 million and lower effective tax rate of $0.8 million, which
were partially offset by a decrease in gas margin of $2.1 million and
higher operating expenses of $0.9 million.
o 2001 vs 2000 Operating revenues increased due to higher average retail
prices. Net income increased primarily as a result of increases in gross
margins on gas sales.
Delivered volumes for 2002, 2001 and 2000 totaled approximately 33.8
million, 36.0 million and 43.1 million DT, 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 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000
------------------------------------- --------------- ----------------
Operating revenues $316.8 $613.4 $677.9
Net income (loss) (.8) 3.4 (3.1)
------------------------------------- --------------- ----------------
o 2002 vs 2001 Operating revenues decreased primarily due to lower natural
gas prices and lower volumes. Net income decreased $5.3 million primarily
from the decreased activity and subsequent closing of SCANA Energy Trading,
LLC and $1.7 million due to lower margins related to decreased gas prices
and decreased volumes. These decreases were partially offset by increases
of $1.3 million due to the closing of the unprofitable Midwest office in
2001 and $1.5 million lower bad debt expense.
o 2001 vs 2000 Operating revenues decreased $104.8 million primarily due to
the closing of the Midwest and California offices in 2001, which was
partially offset $40.3 million by higher average retail prices. Net income
improved primarily due to improved margins.
Delivered volumes for 2002, 2001 and 2000 totaled approximately 86.2
million, 114.6 million and 149.6 million DT, respectively. The decrease in
volumes for 2001 resulted from the closing of the Midwest and California
offices.
Other Operating Expenses
Increases (decreases) in other operating expenses were as follows:
Millions of dollars 2002 % Change 2001 % Change
- ------------------------------------------ -------------------------------------
Other operation and maintenance $41.4 8.6% $3.5 0.7%
Depreciation and amortization (3.8) (1.7%) 7.2 3.3%
Other taxes 11.6 10.1% 1.5 21.3%
- ------------------------------------------ -----------
Total $49.2 6.0% $12.2 1.5%
========================================== =====================================
o 2002 vs 2001 Other operation and maintenance expenses increased primarily
due to lower pension income of $11.6 million, increased labor and benefits
of $19.2 million, increased nuclear refueling maintenance of $4.0 million,
increased cost at Cogen South of $3.1 million, higher property insurance of
$2.6 million, increased amortization of environmental costs of $3.0 million
and increased storm damage expenses of $1.8 million. These increases were
partially offset by lower bad debt expense of $7.0 million. Depreciation
and amortization decreased primarily due to implementation of SFAS 142 and
the resulting elimination of amortization expense related to goodwill of
$14.0 million - see Note 1G of Notes to Consolidated Financial Statements,
which was partially offset by increases for the completion of the Urquhart
Station repowering project in June 2002 of $4.8 million and normal net
property additions of $5.4 million. Other taxes increased primarily due to
increased property taxes.
o 2001 vs 2000 Other operation and maintenance expenses increased primarily
as a result of increases in employee benefits. Depreciation and
amortization increased primarily as a result of normal increases in utility
plant. Other taxes increased 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 2002 % Change 2001 % Change
- ------------------------------------------ ---------------------------------
Gain on sale of investments $(521.7) * $545.3 *
Gain on sale of assets 4.1 33.3% 10.5 *
Impairment of investments (228.8) * (61.9) *
Other income 8.6 21.7% 0.4 1.0%
- ------------------------------------------ ----------
Total $(737.8) * $494.3 *
========================================== =================================
*Not meaningful
o 2002 vs 2001 Gain on sale of investments was higher in 2001 than 2002
primarily as a result of the gain of $545.3 million 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 of $7.8 million on the sale of the
assets of SCANA Security. In 2002, the Company recognized gains of $15.6
million and $23.6 million in connection with the sale of the Company's
radio service network and the sale of all DTAG stock. Impairment of
investments increased due to the impairment writedowns of the Company's
investments in DTAG and ITC^DeltaCom.
o 2001 vs 2000 Other income increased primarily as a result of the 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
impairments related to investments in ITC^DeltaCom, a developer of
micro-turbine technology and a lime production plant.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
Millions of dollars 2002 % Change 2001 % Change
---------------------------------------------------------------------------
Interest on long-term debt, net $(18.8) (8.4%) $17.8 8.6%
Other interest expense (4.0) (39.6%) (14.4) (58.8)%
------------------------------------------- ----------
Total $(22.8) (9.8%) $3.4 1.5%
===========================================================================
o 2002 vs 2001 Interest expense decreased by $18.8 million as a result of
lower interest rates, by $2.0 million due to decreased borrowings and by
$1.4 million due to lower amortization of debt expense which occurred as a
result of debt payoffs.
o 2001 vs 2000 Interest expense increased by $20.0 million due to increased
borrowings. Such increase was partially offset by decreases of $6.0 million
due to declining variable interest rates, $5.2 million due to the Company's
use of interest rate swap contracts to convert higher fixed rate debt to
lower variable rate debt and by $5.4 million due to a decrease in the
principal and weighted average interest rate on short-term debt.
Income Taxes
Income taxes decreased approximately $268.9 million in 2002 compared to
2001 and increased approximately $163.8 million in 2001 compared to 2000.
Changes in income taxes are primarily due to changes in Other Income described
above. The Company's effective tax rate for 2002, excluding the cumulative
effect of accounting change, was approximately 26.7%, which reflects the impact
of higher equity AFC and the change in tax regulations effective in 2002
allowing for the tax deductibility of certain dividends paid on SCANA stock held
in the Company's Stock Purchase Savings Plan .
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The tables below provide information about long-term
debt issued by the Company and other financial instruments that are sensitive to
changes in interest rates. For debt obligations the tables present principal
cash flows and related weighted average interest rates by expected maturity
dates. For interest rate swaps, the figures shown reflect notional amounts and
related maturities. Fair values for debt and swaps represent quoted market
prices.
December 31, 2002 Expected Maturity Date
Millions of dollars
Liabilities 2003 2004 2005 2006 2007 Thereafter Total Fair Value
----------------------------------- -------- --------- --------- ---------- ----------- ----------- ----------- --------------
Long-Term Debt:
Fixed Rate ($) 313.3 201.9 196.8 177.3 71.3 2,174.2 3,134.8 3,267.2
Average Fixed Interest Rate (%) 7.26 7.51 7.37 8.47 6.94 6.73 6.97
Variable Rate ($) 100.0 150.0 - - - 250.0 249.3
-
Average Variable Interest Rate 3.11 2.71 - - - 2.87
(%) -
Interest Rate Swaps:
Pay Variable/Receive Fixed ($) 7.5 57.5 3.2 3.2 28.2 241.0 340.6 9.0
Average Pay Interest Rate (%) 6.17 6.13 4.59 4.59 4.60 3.05 3.79
Average Receive Interest Rate 9.47 7.70 8.75 8.75 7.11 6.21 6.65
(%)
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 ($) 4.3 7.5 7.5 3.2 3.2 319.2 344.9 1.2
Average Pay Interest Rate (%) 7.82 6.73 6.73 5.26 5.26 3.08 3.34
Average Receive Interest Rate 10.0 9.47 9.47 8.75 8.75 6.46 6.68
(%)
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, at December 31, 2002 the Company held investments in the 12%
senior unsecured notes (due 2009) of a telecommunications company, the cost
basis of which, including accrued interest, is approximately $43.6 million. As
these notes are not actively traded, determination of their fair value is not
practicable.
Commodity price risk - The tables below provide information about the
Company's financial instruments that are sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu. Fair values
represent quoted market prices.
As of December 31, 2002
Millions of dollars, except weighted average settlement price and
strike price
Natural Gas Derivatives: Expected Maturity in 2003
- --------------------------- ---------------------------------
Settlement Contract Fair
Price (a) Amount Value
Futures Contracts:
Long($) 4.65 15.6 18.7
Short($) 4.62 3.6 4.5
Strike Contract
Price Amount
(a)
Options:
Purchased put (short)($) 4.25 8.8
Purchased call (long)($) 4.11 16.5
Sold put (long) ($) 2.30 2.7
- --------------------------- ----------- ---- ----------------
As of December 31, 2001
Millions of dollars, except weighted average settlement price
Natural Gas Derivatives: Expected Maturity in 2002 Expected Maturity in 2003
- --------------------------- --------------------------------- -----------------------------------------------
Settlement Contract Fair Settlement Contract Fair
Price (a) Amount Value Price (a) Amount Value
Futures Contracts:
Long($) 2.63 119.3 76.0 3.26 3.0 2.6
Short($) 2.64 1.6 1.1 - - -
(a) weighted average
The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of various 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.
Policies and procedures and risk limits are established to control the
level of market, credit, liquidity and operational and administrative risks
assumed by the Company. The Company's Board of Directors has delegated to a Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and oversee and review the risk
management process and infrastructure. The Risk Management Committee, which is
comprised of certain officers, including the Company's Risk Management Officer,
and senior officers of the Company, provides assurance to the Board of Directors
with regard to the management of risk and brings to the Board's attention any
areas of concern. Written policies define the physical and financial
transactions that are approved, as well as the authorization requirements and
limits for transactions that are allowed.
The NYMEX futures information above includes those financial positions of
both Energy Marketing and SCPC. Certain derivatives that SCPC utilizes to hedge
its gas purchasing activities are recoverable through its weighted average cost
of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA)
clause that provides for the recovery of actual gas costs incurred. The SCPSC
has ruled that the results of SCPC's hedging activities are to be included in
the PGA. The offset to the change in fair value of these derivatives is recorded
as a regulatory asset or liability.
Beginning in January 2003, PSNC Energy initiated a hedging program for gas
purchasing activities using NYMEX futures and options. PSNC Energy's tariffs
include a PGA clause that provides for the recovery of actual gas costs
incurred. PSNC Energy will include in its PGA the results of its hedging
program, and will seek approval of this accounting treatment from the NCUC
during the annual prudence review in 2003. The offset to the change in fair
value of these derivatives will be recorded as a regulatory asset or liability.
Equity price risk - Investments in telecommunications companies' equity
securities (excluding preferred stock with significant debt characteristics) are
carried at market value or, if market value is not readily determinable, at
cost. The carrying value of the Company's investments in such securities totaled
$109.1 million at December 31, 2002. A temporary decline in value of ten percent
would result in a $10.9 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 (Loss). An other than
temporary decline in value of ten percent would result in a $10.9 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.............................................. 56
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001........... 57
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000 .................................. 59
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000................................... 60
Consolidated Statements of Capitalization as of December 31,
2002 and 2001...................................................... 61
Consolidated Statements of Comprehensive Income and Changes in Common
Equity for the Years Ended December 31, 2002, 2001 and 2000 ....... 63
Notes to Consolidated Financial Statements............................. 64
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, 2002 and 2001
and the related Consolidated Statements of Operations, Comprehensive Income
(Loss) and Changes in Common Equity and of Cash Flows for each of the three
years in the period ended December 31, 2002. Our audits also include the
financial statement schedule listed in Part IV at Item 15. These financial
statements and financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with 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, 2002
and 2001 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002 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 Notes 1 and 2 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets," effective January 1, 2002 and changed its method
of accounting for operating revenues associated with its regulated utility
operations effective January 1, 2000.
s/Deloitte & Touche LLP
Columbia, South Carolina
February 7, 2003
SCANA Corporation
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------
December 31, (Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------
Assets
Utility Plant (Note 6):
Electric $5,228 $4,855
Gas 1,593 1,536
Other 184 187
- ------------------------------------------------------------------------------
Total 7,005 6,578
Accumulated depreciation and amortization (2,476) (2,364)
- ------------------------------------------------------------------------------
Total 4,529 4,214
Construction work in progress 677 544
Nuclear fuel, net of accumulated amortization 38 45
Acquisition adjustments, net of accumulated
amortization (Notes 2 & 3) 230 460
- ------------------------------------------------------------------------------
Utility Plant, Net 5,474 5,263
- ------------------------------------------------------------------------------
Nonutility Property, Net of Accumulated Depreciation 95 93
Investments (Note 11) 231 194
- ------------------------------------------------------------------------------
Nonutility Property and Investments, Net 326 287
- ------------------------------------------------------------------------------
Current Assets:
Cash and temporary investments (Note 11) 397 212
Receivables, net of allowance for uncollectible
accounts of $17 and $37 486 424
Inventories (at average cost):
Fuel 166 164
Materials and supplies 61 59
Emission allowances 10 13
Prepayments 40 21
Investments (Note 11) - 664
- ------------------------------------------------------------------------------
Total Current Assets 1,160 1,557
- ------------------------------------------------------------------------------
Deferred Debits:
Environmental 27 34
Nuclear plant decommissioning fund 87 79
Pension asset, net (Note 5) 265 239
Other regulatory assets 269 210
Other 146 153
- ------------------------------------------------------------------------------
Total Deferred Debits 794 715
- ------------------------------------------------------------------------------
Total $7,754 $7,822
==============================================================================
------------------------------------------------------------------------- ------------------- ---------------------
December 31, (Millions of dollars) 2002 2001
------------------------------------------------------------------------- ------------------- ---------------------
Capitalization and Liabilities
Shareholders' Investment:
Common equity (Note 8) $2,177 $2,194
Preferred stock (Not subject to purchase or sinking funds) (Note 9) 106 106
------------------------------------------------------------------------- ------------------- ---------------------
Total Shareholders' Investment 2,283 2,300
Preferred Stock, net (Subject to purchase or sinking funds) (Note 9) 9 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 9) 50 50
Long-Term Debt, net (Notes 6 & 11) 2,834 2,646
------------------------------------------------------------------------- ------------------- ---------------------
Total Capitalization 5,176 5,006
------------------------------------------------------------------------- ------------------- ---------------------
Current Liabilities:
Short-term borrowings (Notes 7 & 11) 209 165
Current portion of long-term debt (Notes 6 & 11) 413 739
Accounts payable 363 275
Customer deposits 39 41
Taxes accrued 78 82
Interest accrued 52 45
Dividends declared 39 34
Deferred income taxes, net (Note 10) 4 154
Other 42 26
------------------------------------------------------------------------- ------------------- ---------------------
Total Current Liabilities 1,239 1,561
------------------------------------------------------------------------- ------------------- ---------------------
Deferred Credits:
Deferred income taxes, net (Note 10) 747 720
Deferred investment tax credits (Note 10) 118 118
Reserve for nuclear plant decommissioning 87 79
Postretirement benefits (Note 5) 131 122
Other regulatory liabilities 114 100
Other 142 116
------------------------------------------------------------------------- ------------------- ---------------------
Total Deferred Credits 1,339 1,255
------------------------------------------------------------------------- ------------------- ---------------------
Commitments and Contingencies (Note 12) - -
------------------------------------------------------------------------- ------------------- ---------------------
Total $7,754 $7,822
========================================================================= =================== =====================
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF OPERATIONS
------------------------------------------------------------------------ ---------------- --------------- -------------- --
For the Years Ended December 31, 2002 2001 2000
------------------------------------------------------------------------ ---------------- --------------- -------------- --
(Millions of Dollars, except per share amounts)
Operating Revenues (Notes 2 & 4):
Electric $1,380 $1,369 $1,344
Gas - regulated 878 1,015 998
Gas - nonregulated 696 1,067 1,091
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Operating Revenues 2,954 3,451 3,433
------------------------------------------------------------------------ ---------------- --------------- ----------------
Operating Expenses:
Fuel used in electric generation 330 283 295
Purchased power 42 138 82
Gas purchased for resale 1,199 1,681 1,694
Other operation and maintenance 522 482 477
Depreciation and amortization 220 224 217
Other taxes 127 115 114
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Operating Expenses 2,440 2,923 2,879
------------------------------------------------------------------------ ---------------- --------------- ----------------
Operating Income 514 528 554
------------------------------------------------------------------------ ---------------- --------------- ----------------
Other Income (Expense):
Other income, including allowance for equity funds
used during construction of $23, $15 and $3 71 55 41
Gain on sale of investments and assets (Note 11) 40 557 3
Impairment of investments (Note 11) (291) (62) -
------------------------------------------------------------------------ ---------------- --------------- ----------------
Total Other Income (Expense) (180) 550 44
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Interest Charges, Income Taxes, Preferred Stock
Dividends and Cumulative Effect of Accounting Change 334 1,078 598
Interest Charges, Net of Allowance for Borrowed Funds
Used During Construction of $12, $11 and $6 199 223 225
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 135 855 373
Income Taxes (Note 10) 36 305 141
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 99 550 232
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 95 546 228
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) 7 7 7
------------------------------------------------------------------------ ---------------- --------------- ----------------
Income Before Cumulative Effect of Accounting Change 88 539 221
Cumulative Effect of Accounting Change, net of taxes (Note 2) (230) - 29
------------------------------------------------------------------------ ---------------- --------------- ----------------
Net Income (Loss) $(142) $539 $250
======================================================================== ================ =============== ================
Basic and Diluted Earnings (Loss) Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $0.83 $5.15 $2.12
Cumulative Effect of Accounting Change, net of taxes (Note 2) (2.17) - .28
------------------------------------------------------------------------ ---------------- --------------- ----------------
Basic and Diluted Earnings (Loss) Per Share $(1.34) $5.15 $2.40
======================================================================== ================ =============== ================
Weighted Average Common Shares Outstanding (millions) 106.0 104.7 104.5
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
For the Years Ended December 31, (Millions of dollars) 2002 2001 2000
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Operating Activities:
Net income (loss) $(142) $539 $250
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
Cumulative effect of accounting change, net of taxes 230 - (29)
Depreciation and amortization 233 236 227
Amortization of nuclear fuel 20 16 16
Gain on sale of assets and investments (40) (558) (3)
Impairment of investments 291 62 -
Hedging activities 42 (65) -
Allowance for funds used during construction (35) (26) (9)
Over (under) collection, fuel adjustment clauses (15) 20 (25)
Changes in certain assets and liabilities:
(Increase) decrease in receivables (64) 262 (258)
(Increase) decrease in inventories (1) (53) 3
(Increase) decrease in prepayments (19) (18) 3
(Increase) decrease in pension asset (26) (43) (43)
(Increase) decrease in other regulatory assets 6 (3) 4
Increase (decrease) in deferred income taxes, net (185) 189 61
Increase (decrease) in other regulatory liabilities 39 22 6
Increase (decrease) in postretirement benefits 9 9 15
Increase (decrease) in accounts payable 88 (119) 155
Increase (decrease) in taxes accrued (4) 28 (55)
Increase (decrease) in interest accrued 7 3 9
Changes in other assets 8 8 9
Changes in other liabilities 52 (13) 55
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Provided From Operating Activities 494 496 391
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (675) (523) (334)
Purchase of subsidiary, net of cash acquired - - (212)
Proceeds on sale of investments and assets 568 28 8
Increase in nonutility property (19) (25) (27)
Investments in affiliates (62) (46) (20)
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Used For Investing Activities (188) (566) (585)
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of common stock 149 - -
Issuance of First Mortgage Bonds 295 149 148
Issuance of Industrial Revenue Bonds 87 - -
Issuance of notes and loans 497 648 998
Swap settlement 29 6 -
Repayments:
Mortgage bonds (104) - (100)
Notes and loans (915) (317) (183)
Pollution Control Facilities Revenue Bonds (62) - -
Retirement of preferred stock (1) - (1)
Retirement of common stock - - (488)
Dividends and distributions:
Common stock (133) (123) (124)
Preferred stock (7) (7) (7)
Short-term borrowings, net 44 (233) (6)
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Provided From (Used For) Financing Activities (121) 123 237
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Increase in Cash and Temporary Investments 185 53 43
Cash and Temporary Investments, January 1 212 159 116
- --------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash and Temporary Investments, December 31 $397 $212 $159
============================================================================================= ============ ============ ============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $12, $6 and $4) $192 $219 $207
- Income taxes 190 71 120
Noncash Investing and Financing Activities:
Unrealized gain (loss) on securities available for sale, net of tax 87 (226) (197)
Columbia Franchise Agreement 30 - -
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) 2002 2001
- ---------------------------------------------------------------------------------------- ------------- ------- ----------- --------
Common Equity (Note 8):
Common stock, without par value, authorized 150,000,000 shares; issued and
outstanding, 110,831,307 shares in 2002 and 104,728,208 in 2001 $1,192 $1,043
Accumulated other comprehensive income (loss) 1 (113)
Retained earnings 984 1,264
- ---------------------------------------------------------------------------------------- ------------- ------- ----------- --------
Total Common Equity 2,177 42% 2,194 44%
- ---------------------------------------------------------------------------------------- ------------- ------- ----------- --------
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
Outstanding
Series 2002 2001 Redemption Price
------ ---- ---- ----------------
$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 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 2002
and 2001 $50 Par Value - Authorized 1,539,973 shares
Shares Outstanding
Series 2002 2001 Redemption Price
------ ---- ---- ----------------
4.50% & 4.60% (A) 18,849 22,449 $51.00 1 2
4.60% (B) 51,000 54,400 50.50 3 3
5.125% 65,000 66,000 51.00 3 3
6.00% 65,124 66,635 50.50 3 3
--------- ------------
Total 199,973 209,484
========= ============
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 2002 and 2001
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
Total Preferred Stock (Subject to purchase or sinking funds) 10 11
Less: Current portion, including sinking fund requirements (1) (1)
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11) 9 - % 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 9) 50 1% 50 1%
- ----------------------------------------------------------------------------------------- ------------ -------- ------------ -------
- --------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
December 31, (Millions of dollars) 2002 2001
- --------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
Long-Term Debt (Notes 6 & 11)
SCANA Corporation: Series Year of Maturity
Medium-Term Notes: 3.08%(1) 2002 - $300
2.63%(1) 2002 - 400
6.51% 2003 $20 20
6.05% 2003 60 60
6.25% 2003 75 75
3.45%(1) 2003 - 202
2.275%(2) 2003 100 -
7.44%(3) 2004 50 50
2.315%(4) 2004 150 -
6.90%(3) 2007 25 25
5.81%(3) 2008 115 115
6.875% 2011 300 300
6.25%(3) 2012 250 -
Fair value of interest rate swaps 40 7
South Carolina Electric & Gas Company: Series Year of Maturity
First Mortgage Bonds: 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 150 150
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
6.63% 2032 300 -
First and Refunding Mortgage Bonds: 9% 2006 131 131
8 7/8% 2021 - 103
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984 (6.50%) - 57
Orangeburg County Series 1994, due 2024 (5.70%) 30 30
Other 11 16
Industrial Revenue Bonds (4.2%-5.5%) 90 -
Franchise Agreements 17 4
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 38 41
Public Service Company of North Carolina, Incorporated:
Series Year of Maturity
Senior Debentures: 10%(3) 2004 9 13
8.75%(3) 2012 32 32
6.99% 2026 50 50
7.45% 2026 50 50
Medium-Term Notes 6.625% 2011 150 150
Fair value of interest rate swaps 3 -
South Carolina Pipeline Corporation Notes, 6.72%, due 2013 14 15
Other 5 6
- --------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
Total Long-Term Debt 3,251 3,388
Less - Current maturities, including sinking fund requirements (413) (738)
- Unamortized discount (4) (4)
- --------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
Total Long-Term Debt, Net 2,834 55% 2,646 53%
- --------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
Total Capitalization $5,176 100% $5,006 100%
=========================================================================== ====== =========== ======= ============== ===========
(1) Rate at repayment
(2) Current rate, based on three-month LIBOR + 87.5 basis points reset
quarterly (3) Fixed rate debt hedged by variable interest rate swap
(4) Current rate, based on three-month LIBOR + 62.5 basis points reset
quarterly
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND CHANGES IN COMMON EQUITY
- ------------------------------------------------ ------------------------- ------------------------- ---------------------------
For the years Ended December 31, 2002 2001 2000
- ------------------------------------------------ ------------------------- ------------------------- ---------------------------
(Millions of Dollars)
Common Comprehensive Common Comprehensive Common Comprehensive
Equity Income (Loss) Equity Income Equity Income
Retained Earnings:
Balance at January 1 $1,264 $850 $720
Net Income (loss) (142) $(142) 539 $539 250 $250
Dividends declared on common stock (138) (125) (120)
--------- --------- ---------
Balance at December 31 984 1,264 850
-------- -------- ----- ---
Accumulated other comprehensive income (loss):
Balance at January 1 - 23 23 - -
($12 in 2001)
Unrealized gains (loss) on hedging
activities,
net of taxes ($15 and $(26) in 2002
and 2001,
respectively) 27 27 (49) - -
-------- -- ---- --- ---- --------- ----- -
(49)
Comprehensive income (loss) $(28) $287 $53
===== ==== = ===
Balance at December 31 1 (113) 139
--------- ------- ---- ---
Common Stock:
Balance at January 1 1,043 1,043 1,043
Shares issued 149 488
-
Shares repurchased - (488)
--------- --------- ---------
-
Balance at December 31 1,192 1,043 1,043
- ----- -- ----- -- -----
Total Common Equity $2,177 $2,194 $2,032
====== ====== ======
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, holds investments in
telecommunications companies and provides fiber optic communications in South
Carolina.
The accompanying Consolidated Financial Statements reflect the accounts
of the Company, the following wholly owned subsidiaries, and three other wholly
owned subsidiaries in liquidation.
Regulated businesses Nonregulated businesses
South Carolina Electric & Gas Company (SCE&G) SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc. (Fuel Company) SCANA Communications, Inc.(SCI)
South Carolina Generating Company, Inc. (GENCO) ServiceCare, Inc.
South Carolina Pipeline Corporation (SCPC) Primesouth, Inc.
Public Service Company of North Carolina, SCANA Resources, Inc.
Incorporated (PSNC Energy) SCANA Services, Inc.
SCG Pipeline, Inc.
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, "Accounting for the
Effects of Certain Types of Regulation." SFAS 71 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, 2002,
approximately $296 million and $114 million of regulatory assets and
liabilities, respectively, as shown below.
December 31,
Millions of dollars 2002 2001
- ------------------------------------------------------------- ---------------
- ------------------------------------------------------------- ---------------
Accumulated deferred income taxes, net $95 $98
Under- (over-) collections - Electric
Fuel and Gas Cost Adjustment Clauses 61 46
Deferred environmental remediation costs 27 35
Deferred non-conventional fuel tax benefits, net (40) (17)
Storm damage reserve (32) (26)
Franchise agreements 65 -
Other 6 8
- ------------------------------------------------------------- ---------------
- ------------------------------------------------------------- ---------------
Total $182 $144
============================================================= ===============
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates for which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under- (over-) collections - fuel adjustment clauses represent amounts
over- or under-collected from customers pursuant to the fuel adjustment clause
(electric customers) or gas cost adjustment clause (gas customers) as approved
by the Public Service Commission of South Carolina (SCPSC) or North Carolina
Utilities Commission (NCUC) during annual hearings (see Note 1F).
Deferred environmental remediation costs represent costs associated
with the assessment and clean up of environmental sites at manufactured gas
plant (MGP) sites currently or formerly owned by the Company. Costs incurred at
sites owned by SCE&G are being recovered through rates, and such costs, totaling
approximately $18 million, are expected to be fully recovered by the end of
2005. A portion of the costs incurred at sites owned by PSNC Energy are also
being recovered through rates, and management believes the remaining costs of
approximately $7.8 million will be recoverable in the future. Amounts incurred
to date that have not been recovered through gas rates are approximately $1.2
million.
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two SCE&G partnerships involved in converting coal
to alternate fuel. Under a plan approved by the SCPSC, any net tax credits
generated from non-conventional fuel produced and consumed by SCE&G and
ultimately passed through to SCE&G have been and will be deferred and will be
applied to offset the capital costs of projects required to comply with
legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account
capped at $50 million to be collected through rates over a ten-year period. The
accumulated storm damage reserve can be applied to offset actual storm damage
costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year
electric and gas franchise agreements with the cities of Charleston and
Columbia, South Carolina.
The SCPSC and the NCUC have reviewed and approved through specific
orders most of the items shown as regulatory assets. Other items represent costs
which are not yet approved for recovery by the SCPSC or the NCUC. In recording
these costs as regulatory assets, management believes the costs will be
allowable under existing rate-making concepts that are embodied in rate orders
received by the Company. However, ultimate recovery is subject to 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 the
Federal Energy Regulatory Commission (FERC).
D. Utility Plant and Major Maintenance
Utility plant is stated substantially at original cost. The costs of
additions, renewals and betterments to utility plant, including direct labor,
material and indirect charges for engineering, supervision and an allowance for
funds used during construction, are added to utility plant accounts. The
original cost of utility property retired or otherwise disposed of is removed
from utility plant accounts and generally charged, 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 $962.4 million
and $963.0 million as of December 31, 2002 and 2001, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was approximately
$417.9 million and $407.4 million as of December 31, 2002 and 2001,
respectively. SCE&G's share of the direct expenses associated with operating
Summer Station is included in "Other operation and maintenance" expenses and
totaled approximately $76.4 million for the year ended December 31, 2002.
Planned major maintenance other than that related to nuclear outages is
expensed when incurred. The only major maintenance that is accrued in advance of
the time the costs are actually incurred is that related to the nuclear
refueling outages for which such accounting treatment and rate recovery of
expenses accrued thereunder has been approved by the SCPSC. Nuclear outages are
scheduled 18 months apart, and SCE&G begins accruing for each successive outage
immediately upon completion of the preceding outage. For the outage ended June
2002, SCE&G accrued approximately $0.5 million per month from January 2001
through June 2002 and is now accruing approximately $0.6 million per month for
its portion of the outage scheduled in October 2003. Total outage costs for the
planned outage in October 2003 are estimated to be approximately $17 million, of
which SCE&G will be responsible for approximately $11.3 million. As of December
31, 2002, SCE&G had accrued $3.8 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 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, 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 $107.7 million
and $81.1 million as of December 31, 2002 and 2001, 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 $25.3 million and $47.4 million at
December 31, 2002 and 2001, respectively, which amounts 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, 2002 and 2001 SCE&G had undercollected
through the gas cost recovery procedure approximately $24.6 million and $12.2
million, respectively, which amounts are also included in "Deferred Debits -
Other regulatory assets." At December 31, 2002 PSNC Energy had undercollected
through the gas cost recovery procedure approximately $10.6 million which amount
is also included in "Deferred Debits - Other regulatory assets." At December 31,
2001 PSNC Energy had overcollected through the gas cost recovery procedure
approximately $13.8 million which amount is included in "Deferred Credits -
Other regulatory liabilities."
SCE&G's and PSNC Energy's gas rate schedules for residential, small
commercial and small industrial customers include a weather normalization
adjustment which minimizes fluctuations in gas revenues due to abnormal weather
conditions.
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:
2002 2001 2000
- --------------------------------------- -------------- ---------------
SCE&G 2.93% 2.98% 2.98%
GENCO 2.66% 2.71% 2.67%
SCPC 2.14% 2.60% 2.58%
PSNC Energy 4.29% 4.06% 4.15%
Aggregate of Above 3.06% 3.09% 3.09%
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 Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. The Company considers the amounts categorized by FERC
as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased
amortization of such amounts upon the adoption of SFAS 142. These amounts are
related to acquisition adjustments of approximately $466 million recorded on the
books of PSNC Energy (Gas Distribution segment) and approximately $40 million
recorded on the books of SCPC (Gas Transmission segment). The Company has no
other intangible assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization of acquisition adjustments during
all periods presented in the consolidated statements of operations, net income
(loss) and basic and diluted earnings (loss) per share would have been as
follows:
(Millions of dollars, except per share amounts) 2002 2001 2000
---- ---- ----
Net Income (Loss) as Reported $(142) $539 $250
Amortization of Acquisition Adjustment - 14 14
------ - --- -- --- --
Net Income (Loss) as Adjusted $(142) $553 $264
====== ==== ====
Basic and Diluted Earnings (Loss) Per Share As Reported $(1.34) $5.15 $2.40
Amortization of Acquisition Adjustment - .14 .14
------- - --- --- --- ---
Basic and Diluted Earnings (Loss) Per Share As Adjusted $(1.34) $5.29 $2.54
======= ===== =====
In connection with implementation of SFAS 142, the Company performed a
valuation analysis of its investment in SCPC using a discounted cash flow
analysis and of PSNC Energy using an independent appraisal. The analysis of the
investment in PSNC Energy indicated that the carrying amount of PSNC Energy's
acquisition adjustment exceeded its fair value by approximately $230 million as
of January 1, 2002. As a result, the Company recorded an impairment charge of
$230 million ($2.17 loss per share) in 2002. The charge is reflected on the
statement of operations as the cumulative effect of an accounting change.
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 2002, 2001 and 2000) 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. 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 cost in deferred credits.
See also discussion below related to the adoption of SFAS 143, "Accounting for
Asset Retirements Obligations," effective January 1, 2003.
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 $2.0 million and $2.4
million at December 31, 2002 and 2001, respectively, 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 and Other Taxes
The Company files a consolidated federal income tax return. Under a joint
consolidated income tax allocation agreement, each subsidiary's current and
deferred tax expense is computed on a stand-alone basis. Deferred tax assets and
liabilities are recorded for the tax effects of all significant temporary
differences between the book basis and tax basis of assets and liabilities at
currently enacted tax rates. Deferred tax assets and liabilities are adjusted
for changes in such rates through charges or credits to regulatory assets or
liabilities if they are expected to be recovered from, or passed through to,
customers of the Company's regulated subsidiaries; otherwise, they are charged
or credited to income tax expense.
The Company records excise taxes billed and collected, as well as local
franchise and similar taxes as liabilities until they are remitted to the
respective taxing authority. As such, no excise taxes are included in revenues
or expenses in the statements of operations.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt and are
being amortized as components of "Interest on long-term debt, net" over the
terms of the respective debt issues. Other issuance expense and gains or losses
on reacquired debt that is refinanced are recorded in other deferred debits or
credits and amortized over the term of the replacement debt.
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 solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates. Deferred
amounts for SCE&G, net of amounts previously recovered through rates and
insurance settlements, totaled $17.9 million and $24.4 million at December 31,
2002 and 2001, respectively. Deferred amounts for PSNC Energy totaled $7.8
million and $9.1 million at December 31, 2002 and 2001, respectively. The
deferral includes the estimated costs associated with the matters discussed in
Note 12C.
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 began recognizing assets or
liabilities for the energy-related derivatives contracts entered into by its
subsidiaries when the contracts are executed. The Company records derivatives
contracts at their fair value in accordance with SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended and adjusts fair
value each reporting period. The Company derives fair value of most of the
energy-related derivatives contracts from markets where they are actively traded
and quoted. For other derivatives contracts the Company uses published market
surveys and in certain cases, independent parties to obtain quotes concerning
fair value. Market quotes tend to be more plentiful for those derivatives
contracts maturing in two years or less. The vast majority of the Company's
derivatives contracts do not extend beyond two years. (See Note 11). SCPC's
tariffs include a purchased gas adjustment (PGA) clause that provides for the
recovery of actual gas costs incurred. The SCPSC has ruled that the results of
SCPC's hedging activities are to be included in the PGA. As such, costs of
related derivatives are recoverable through its weighted average cost of gas
calculation. The offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
N. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method.
SFAS 142 addresses how goodwill and other intangible assets should be accounted
for after they have been recorded in the financial statements. (See Notes 1G and
2).
In June 2001, FASB issued SFAS 143, which becomes effective for
financial statements issued for fiscal years beginning after June 15, 2002.
Accordingly, the Company adopted this standard effective January 1, 2003. SFAS
No. 143 applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods.
The Company has determined that it should recognize an ARO related to
the decommissioning and dismantling of Summer Station, and effective January 1,
2003, will record an ARO of approximately $110 million, which amount exceeds the
previously recorded reserve for nuclear plant decommissioning of $87 million,
and a net capital asset of approximately $20 million. Due to the application of
SFAS 71, the difference between these amounts will be recorded in regulatory
accounts and will have no impact on the Company's results of operations or cash
flows.
In addition to the ARO for Summer Station, the Company believes that
there is legal uncertainty as to the existence of environmental obligations
associated with certain transmission and distribution properties. The Company
believes that any ARO related to this type of property would be insignificant
and, due to the indeterminate life of the related assets, an ARO could not be
reasonably estimated.
The Company's regulated operations record cost of removal as a component
of accumulated depreciation for property that does not have an associated legal
retirement obligation. As of December 31, 2002, the Company estimates that
approximately $325 million of its accumulated depreciation balance is related to
this regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became 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.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treatment of gains or
losses from the early extinguishment of debt as extraordinary items unless such
early extinguishment meets the criteria of Accounting Principles Board Opinion
(APB) 30. The Company will adopt SFAS 145 effective January 1, 2003, and does
not expect that initial adoption will have any impact on the Company's results
of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
SFAS 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure" was issued in December 2002 and amends SFAS 123, "Accounting for
Stock-Based Compensation" to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. It also amends the disclosure requirements of SFAS 123 to
require prominent disclosure in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company will adopt the
disclosure provisions of SFAS 148 effective January 1, 2003, and does not expect
that initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
O. Stock Option Plan
Under the SCANA Corporation Long-Term Equity Compensation Plan, certain
employees and non-employee directors may receive incentive and nonqualified
stock options and other forms of equity compensation. The Company accounts for
this equity-based compensation using the intrinsic value method under APB 25,
"Accounting for Stock Issued to Employees," and related interpretations. In
addition, the Company has adopted the disclosure provisions of SFAS 123,
"Accounting for Stock-Based Compensation" and, effective January 1, 2003, the
provisions of SFAS 148 "Accounting for Stock-Based Compensation - Transition and
Disclosure."
P. Earnings Per Share
Earnings (loss) 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 2002.
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. Accounting ChangeS
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to the acquisition adjustment
recorded in connection with its investment in PSNC Energy. This charge is
reflected on the Consolidated Statements of Operations as the cumulative effect
of an accounting change. See additional information at Note 1G.
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.
3. ACQUISITION
Effective January 1, 2000 the Company acquired PSNC Energy in a business
combination accounted for as a purchase. PSNC Energy is a public utility engaged
primarily in purchasing, transporting, distributing and selling natural gas to
approximately 384,000 residential, commercial and industrial customers in 27 of
its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan
of Merger, PSNC Energy 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 Energy are included in the accompanying financial statements as of
January 1, 2000, the effective date of the 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 (see Note 1G).
4. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
In December 2002 the SCPSC issued an order approving SCE&G's request to
capitalize the cost of fuel consumed in the production of test power for the gas
turbines installed at Urquhart Generating Station in 2002. As a result, SCE&G
transferred approximately $12.5 million from fuel used in electric generation to
electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for 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 2002. In January 2003 in
conjunction with the approval of the above retail rate increase, the SCPSC
approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh.
This reduction is effective for service rendered on or after February 1, 2003.
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, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001
$.728 November-December 2002 $.793 March-October 2001
$.596 November-December 2001
The SCPSC allows SCE&G 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 recorded in deferred debits. In October 2002, as a result of the annual
review, the SCPSC reaffirmed SCE&G's billing surcharge of 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, 2002 of $17.9 million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over eight years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City.
SCE&G will continue to operate the plant for the City until 2005. SCE&G will
also pay the Central Midlands Regional Transit Authority up to $3 million as
matching funds for Federal Transit Administration grants for the purchase of new
transit coaches and a new transit facility. The cost of the franchise agreement
is recorded in other regulatory assets.
Public Service Company of North Carolina, Incorporated
PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually.
PSNC Energy's benchmark cost of gas in effect during the years ended
December 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001
$.215 February-June 2002 $.750 February-March 2001
$.350 July-October 2002 $.650 April-August 2001
$.410 November-December 2002 $.500 September-October 2001
$.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase
the benchmark cost of gas from $.410 to $.460 per therm effective for service
rendered on and after January 1, 2003.
In April 2000 the NCUC issued an order permanently approving PSNC
Energy'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 Energy to collect from its customers amounts approximating
the amounts paid for natural gas.
A state expansion fund, established by the North Carolina General
Assembly and funded by refunds from PSNC Energy's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. In June 2000 the NCUC approved PSNC
Energy's requests for disbursement of up to $28.4 million from PSNC Energy's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties in western North Carolina. PSNC Energy estimates that the cost of this
project will be approximately $31.4 million. The Madison County and Jackson
County portions of the project were completed by the end of 2002. Through
December 31, 2002 approximately $16.9 million had been spent on this project.
The unused portion of PSNC Energy's expansion fund is recorded in prepaid
assets.
In December 1999 the NCUC issued an order approving SCANA's acquisition
of PSNC Energy. As specified in the order, PSNC Energy 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.
South Carolina Pipeline Corporation
SCPC's purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an August 2002 order, the SCPSC
found that for the period January 2001 through March 2002 SCPC's gas purchasing
policies and practices were prudent and that SCPC properly adhered to the gas
cost recovery provisions of its gas tariff.
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 Energy's pension and postretirement benefit
plans were merged with SCANA's plans.
In connection with the joint ownership of Summer Station, as of December
31, 2002 and 2001 the Company has recorded within deferred credits a $9.1
million and $8.4 million obligation, respectively, to Santee Cooper,
representing an estimate of the net pension asset attributable to the Company's
contributions to the pension plan that were recovered through billings to Santee
Cooper for its one-third portion of shared costs. As of December 31, 2002 and
2001, the Company has also recorded a $6.4 million and $6.0 million receivable,
respectively 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 (Income)
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
Millions of dollars 2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
Service cost $9.0 $7.9 $ 8.3 $3.1 $3.0 $ 2.7
Interest cost 39.8 38.5 33.5 12.4 12.1 10.2
Expected return on assets (77.6) (83.5) (76.6) n/a n/a n/a
Prior service cost amortization 6.3 5.8 3.0 0.9 0.9 0.8
Actuarial (gain) loss (4.1) (12.8) (12.2) 1.1 0.7 -
Transition amount amortization 0.8 0.8 0.8 0.8 0.8 0.8
---- --- ---- --- ----- --- ---- --- ----- --- ---- ---
Net periodic benefit (income) $(25.8) $(43.3) $(43.2) $18.3 $17.5 $14.5
======= ====== ====== ===== ===== =====
cost
Assumptions
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
As of December 31, 2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
Discount rate 6.5% 7.5% 8.0% 6.5% 7.5% 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 2002 2001 2002 2001
---- ---- ---- ----
Benefit obligation, January 1 $530.8 $479.3 $166.7 $139.0
Service cost 9.1 7.9 3.1 3.0
Interest cost 39.8 38.5 12.4 12.1
Plan participants' contributions - - 0.9 0.5
Plan amendment - 21.5 - 1.2
Actuarial loss 50.6 19.6 10.8 20.1
Benefits paid (34.7) (36.0) (10.5) (9.2)
-- ----- -- ----- --- ----- ---- ----
Benefit obligation, December 31 $595.6 $530.8 $183.4 $166.7
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
----------------------------------------------------
Millions of dollars 2002 2001
---- ----
Fair value of plan assets, January 1 $831.6 $894.3
Actual return on plan assets (130.0) (26.7)
Benefits paid (34.7) (36.0)
--- ----- -- -----
Fair value of plan assets, December 31 $666.9 $831.6
====== ======
Funded Status of Plans
Retirement Benefits Other Postretirement
Benefits
----------------------- ---------------------------
Millions of dollars 2002 2001 2002 2001
---- ---- ---- ----
Funded status, December 31 $71.3 $300.8 $(183.4) $(166.7)
Unrecognized actuarial (gain) loss 107.5 (155.0) 42.2 32.5
Unrecognized prior service cost 83.1 89.4 3.9 4.8
Unrecognized net transition obligation 3.1 4.0 6.6
------ --- --------- ------ ---
7.4
Net asset (liability) recognized in Consolidated Balance $265.0 $239.2 $(130.7) $(122.0)
====== ====== ======== == =======
Sheet
Health Care Trends
The determination of net periodic other postretirement health care benefit
cost is based on the following assumptions:
2002 2001 2000
-------------------------------------------------- ---------- ----------
Health care cost trend rate 10.0% 8.5% 7.5%
Ultimate health care cost trend rate 5.0% 5.0% 5.5%
Year achieved 2011 2009 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 1.4 (1.7)
Due to poor performance in the stock market in recent years, the Company
has determined to adjust its long-term expected return on assets to 9.25% for
2003. In developing the expected long-term rate of return assumptions,
management evaluated the plan's historical cumulative actual returns over
several periods, which have all been in excess of related broad indices, and
management anticipates that the plan's investment managers will continue to
generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset
allocation of 80% with equity managers and 20% with fixed income managers. While
the Company believes that the asset allocation will return to those levels,
because of market fluctuations, the actual asset allocation as of December 31,
2002 was 70% with equity managers and 30% with fixed income managers. Management
regularly reviews such allocations and periodically rebalances the portfolio to
the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate
have significantly reduced the level of pension income, the pension trust has
been and remains adequately funded, and no contributions have been required
since 1997. As such, recent declines in pension income have had no impact on the
Company's cash flows.
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 27.10
----------------------------------------- -----------------
Granted 1,116,638 27.56
Exercised (103,677) 27.12
Forfeited (97,332) 27.38
----------------------------------------- -----------------
----------------------------------------- -----------------
Outstanding - December 31, 2002 1,717,910 27.38
----------------------------------------- -----------------
One-third of the options vest on each anniversary of the date of grant
until full vesting occurs. The options expire ten years after the grant date.
Information about outstanding and exercisable options as of December 31, 2002
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 $29.60 1,717,910 8.4 $27.38 274,306 $26.91
- ------------------- ----------------- ------------------- ------------------------------ ----------------
At December 31, 2001 exercisable options totaled 47,275 at a weighted
average exercise price of $25.53. No options were exercisable at December 31,
2000.
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 (loss) and earnings (loss) per share would have been as presented below:
2002 2001 2000
---- ---- ----
Net income (loss) - as reported (millions) $(141.7) $539.3 $250.4
Net income (loss) - pro forma (millions) (143.3) 538.5 250.3
Basic and diluted earnings (loss) per share - as reported (1.34) 5.15 2.40
Basic and diluted earnings (loss) per share - pro forma (1.35) 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 2002, 2001 and
2000 was $4.67, $5.13 and $4.43, respectively, and was estimated using the
Black-Scholes Option pricing model with the following weighted average
assumptions.
2002 2001 2000
---- ---- ----
Expected life of options (years) 7 7 10
Risk free interest rate 4.64% 5.08% 5.99%
Volatility of underlying stock 21% 22% 21%
Dividend yield of underlying stock 4.4% 4.2% 4.4%
6. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2003 through 2007 are summarized as follows:
Year Amount Year Amount
---------------- ----------------- ------------------ -----------------
(Millions of dollars)
2003 $413 2006 $177
2004 352 2007 71
2005 197
---------------- ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt payable in 2003 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.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the Lake Murray dam remediation
project. The loan agreement provides for interest-free borrowings for costs
incurred not to exceed $59 million with such borrowings being repaid over ten
years from the initial borrowing. At December 31, 2002 SCE&G had not yet
borrowed under the agreement.
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 paid the City $25 million over seven years (1996-2002) and
donated to the City the existing transit assets in Charleston.
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia. As part of the transfer agreement, SCE&G will pay the City $32 million
over eight years (2002-2009) in exchange for a 30-year electric and gas
franchise, has conveyed transit-related property and equipment to the City and
has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G
will continue to operate the plant for the City until 2005.
SCE&G has a three-year revolving line of credit totaling $75 million,
expiring in 2005, 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.
On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
Substantially all of SCE&G's utility plant is pledged as collateral in
connection with long-term debt.
7. SHORT-TERM BORROWINGS
Details of lines of credit (including uncommitted lines of credit) and
short-term borrowings at December 31, 2002 and 2001, are as follows:
Millions of dollars 2002 2001
- --------------------------------------------------------- ---------------
Lines of credit $588.0 $588.0
Unused lines of credit $588.0 $588.0
Short-term borrowings outstanding
Commercial paper (270 or fewer days) $208.8 $164.8
Weighted average interest rate 1.40% 1.97%
The Company pays fees to banks as compensation for committed lines of
credit.
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 16, 2003. 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
$50.1 million at December 31, 2002 and 2001, respectively, at weighted average
interest rates of 1.38% and 2.06%, respectively.
SCE&G's commercial paper outstanding totaled $127.6 million and $114.7
million at December 31, 2002 and 2001, at weighted average interest rates of
1.40% and 1.95%, respectively.
PSNC Energy's commercial paper outstanding totaled $31.1 million at
December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had
no commercial paper outstanding at December 31, 2001.
8. COMMON EQUITY
The Company's Restated Articles of Incorporation do not limit the
dividends that may be paid on its common stock. However, the Restated Articles
of Incorporation of SCE&G contain provisions that, under certain circumstances,
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, 2002
approximately $41 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.
In October 2002, six million shares of SCANA common stock were sold,
generating net proceeds of approximately $146 million.
Cash dividends on common stock were declared during 2002, 2001 and 2000
at an annual rate per share of $1.30, $1.20 and $1.15, respectively.
The accumulated balances related to each component of other
comprehensive income (loss) were as follows:
Unrealized Cash flow Accumulated other
gains (losses) hedging comprehensive
Million of dollars on securities activities Income (loss)
- --------------------------------------------------------------------------------
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)
Other comprehensive income 87 27 114
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Balance, December 31, 2002 $- $1 $1
================================================================================
During 2002, $87 million was reclassified from unrealized gains (losses)
on securities into net income (loss) as a result of the recording of an
impairment in the value of the Deutsche Telekom AG investment. The Company also
recognized a loss of approximately $20.6 million, net of tax, as a result of
qualifying cash flow hedges whose hedged transactions occurred during the year
ended December 31, 2002.
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 of Deutsche Telekom AG (DTAG). 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. The Company recognized a loss of approximately
$17.1 million, net of tax, as a result of qualifying cash flow hedges whose
hedged transactions occurred during the year ended December 31, 2001.
There were no realized gains or losses on securities for the year ended
December 31, 2000.
9. PREFERRED STOCK
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 2003 through 2007 is $2.7 million. The call
premium of the respective series of preferred stock in no case exceeds the
amount of the annual dividend.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 2002, 2001 and 2000 are summarized as follows:
Number of Shares Millions of Dollars
- ------------------------------------------------------------------------------
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
Shares Redeemed - $50 par value (9,511) (0.5)
- ------------------------------------------------------------------------------
Balance at December 31, 2002 199,973 $10.0
==============================================================================
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% 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 a like amount of its 7.55% Junior
Subordinated Debentures due September 30, 2027. The sole asset of the Trust is
such 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.
The preferred securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55% 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. 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
effects of accounting changes) for 2002, 2001 and 2000 is as follows:
Millions of dollars 2002 2001 2000
- --------------------------------------------------------------------------------
Current taxes:
Federal $174.6 $91.2 $88.2
State 9.0 11.2 9.2
Foreign 1.0 - -
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total current taxes 184.6 102.4 97.4
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Deferred taxes, net:
Federal (178.5) 182.5 29.8
State .8 1.7 4.7
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total deferred taxes (177.7) 184.2 34.5
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Investment tax credits:
Deferred - State 5.0 5.0 5.0
Amortization of amounts deferred - State (1.7) (1.5) (1.3)
Amortization of amounts deferred - Federal (4.0) (4.0) (4.0)
- --------------------------------------------------------------------------------
Total investment tax credits (0.7) (0.5) (0.3)
- --------------------------------------------------------------------------------
Non-conventional fuel tax credits:
Deferred - Federal 29.8 18.7 9.4
- --------------------------------------------------------------------------------
Total income tax expense $36.0 $304.8 $141.0
================================================================================
The difference between actual income tax expense and the amount
calculated from the application of the statutory 35% federal income tax rate to
pre-tax income (before cumulative effects of accounting changes) is reconciled
as follows:
Millions of dollars 2002 2001 2000
- ----------------------------------------------------------------- --------------- ----------------- -----------------
Income before cumulative effect of accounting change $87.9 $539.3 $221.2
Total income tax expense:
Charged to operating expense 121.6 135.2 152.0
Charged (credited) to other items (85.6) 169.7 (11.0)
Preferred stock dividends 11.2 11.2 11.2
- ----------------------------------------------------------------- --------------- ----------------- -----------------
- ----------------------------------------------------------------- --------------- ----------------- -----------------
Total pre-tax income $135.1 $855.4 $373.4
================================================================= =============== ================= =================
================================================================= =============== ================= =================
Income taxes on above at statutory federal income tax rate $47.3 $299.4 $130.7
Increases (decreases) attributed to:
State income taxes (less federal income tax effect)
8.5 10.7 11.4
Non-deductible book amortization of acquisition adjustments
- 5.0 5.0
Allowance for equity funds utilized during construction
(7.9) (5.2) (1.0)
Deductible dividends - Stock Purchase Savings Plan
(4.5) (1.1) (1.2)
Amortization of federal investment tax credits
(4.0) (4.0) (4.0)
Other differences, net
(3.4) - 0.1
- ----------------------------------------------------------------- --------------- ----------------- -----------------
- ----------------------------------------------------------------- --------------- ----------------- -----------------
Total income tax expense $36.0 $304.8 $141.0
================================================================= =============== ================= =================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $751.1 million at December 31, 2002 and
$873.9 million at December 31, 2001 (see Note 1I), are as follows:
Millions of dollars 2002 2001
- ---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax assets:
Nondeductible reserves $66.9 $69.7
Unamortized investment tax credits 61.0 62.1
Investments in equity securities 25.0 -
Deferred compensation 21.2 23.1
Cycle billing 7.7 8.5
Other 18.6 16.5
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax assets 200.4 179.9
- ---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 814.4 814.3
Investments in equity securities - 133.3
Pension plan benefit income 93.0 81.1
Deferred fuel costs 17.9 22.8
Other 26.2 2.3
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax liabilities 951.5 1,053.8
- ---------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability $751.1 $873.9
================================================================================== ================ ==================
The Internal Revenue Service has examined and closed consolidated federal
income tax returns of the Company through 1997 and is currently examining the
Company's 1998, 1999 and 2000 federal returns. 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, 2002 and 2001 are as follows:
Millions of dollars 2002 2001
- ----------------------------------------------------------- ----------------------------- ----------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- ----------------------------------------------------------- -------------- -------------- ------------- --------------
Assets:
Cash and temporary cash investments $396.7 $396.7 $212.0 $212.0
Investments 231.0 281.3 858.1 944.3
Liabilities:
Short-term borrowings 208.8 208.8 164.8 164.8
Long-term debt 3,247.5 3,516.4 3,384.8 3,501.0
Preferred stock (subject to purchase or sinking funds) 10.0 8.6 10.4 8.5
- ----------------------------------------------------------- -------------- -------------- ------------- --------------
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. Early 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, "Accounting for Certain
Investments in Debt and Equity Securities," mark-to-market accounting and some
of which are considered cost basis investments for which determination of fair
value historically has been considered impracticable. 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 (loss) within common equity on the Company's balance sheet.
Debt securities and preferred stock with significant debt characteristics 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, 2002 SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of SCANA, held investments in the equity and debt
securities of the following companies in the amounts noted in the table below.
Investee Securities Basis
- ------------------ ------------------------------------------------------- ----------------------
(Millions of dollars)
ITC Holding 3.1 million shares common stock $5.8
645,153 shares series A preferred stock, convertible
into
2.6 million shares of common stock 7.2
133,664 shares series B preferred stock, convertible
into
534,656 shares of common stock 4.0
ITC^DeltaCom 566,010 shares of common stock 1.1
149,077 shares series A 8% preferred stock,
convertible in 2005 into 2.6 million shares
of common stock 12.7
Warrants to purchase 506,861.8 shares of common stock 1.1
Knology 7.2 million shares series A preferred stock,
convertible into
7.5 million shares of common stock 14.1
14.8 million shares series C preferred stock,
convertible into
14.8 million shares of common stock 35.1
21.7 million shares series E preferred stock,
convertible
into 21.7 million shares of common stock 40.6
$43.6 million face amount, 12% senior unsecured
notes due 2009, including accrued interest 43.6
In 2002 SCH sold the 39.3 million shares it held in DTAG through a
series of market transactions, receiving after-tax proceeds of approximately
$433 million. In connection with these sales, SCH determined that the decline in
value of its investment in DTAG was other than temporary, and SCH recorded
impairment losses totaling approximately $182 million.
ITC Holding Company (ITC Holding) holds ownership interests in several
Southeastern communications companies. As these securities are not actively
traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc.
(ITC^DeltaCom) is a regional provider of telecommunications services. Knology,
Inc. (Knology) is a broadband service provider of cable television, telephone
and internet services.
In June 2002 ITC^DeltaCom announced plans for a reorganization and
entered into Chapter 11 bankruptcy. As a result the Company wrote off its
investments in ITC^DeltaCom in the second quarter and recorded an aggregate
impairment charge of approximately $7.0 million (after tax). The bankruptcy
court accepted the reorganization plan, and ITC^DeltaCom emerged from bankruptcy
on October 29, 2002. In connection with ITC^DeltaCom's emergence from
bankruptcy, SCH provided $14.9 million in preferred equity financing. The common
shares owned by SCH have a market value of $1.3 million, thus an unrealized gain
of $0.2 million has been recorded in Other Comprehensive Income. The preferred
shares owned by SCH are classified as held to maturity due to their debt
features, and the market value is not readily determinable.
In July 2002 Knology negotiated a potential exchange of its Knology
Broadband discount notes for a combination of new notes and new preferred stock.
In contemplation of the anticipated exchange, the Company recorded an impairment
loss of approximately $0.3 million (after-tax) in the second quarter. Because
the exchange offer did not result in the requisite minimum tender of notes, in
the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which
reflected the same terms of exchange. The bankruptcy court accepted the
reorganization plan, and in connection with Knology's emergence from bankruptcy,
SCH purchased an additional 6.5 million shares of series C preferred stock for
approximately $19.5 million . The market value of Knology securities as of
December 31, 2002 is not readily determinable.
Derivatives
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 (loss), 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.
Policies and procedures and risk limits are established to control the
level of market, credit, liquidity and operational and administrative risks
assumed by the Company. The Company's Board of Directors has delegated to a Risk
Management Committee the authority to set risk limits, establish policies and
procedures for risk management and measurement, and oversee and review the risk
management process and infrastructure. The Risk Management Committee, which is
comprised of certain officers, including the Company's Risk Management Officer,
and senior officers of the Company, provides assurance to the Board of Directors
with regard to the management of risk and brings to the Board's attention any
areas of concern. Written policies define the physical and financial
transactions that are approved, as well as the authorization requirements and
limits for transactions 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 to other
comprehensive income (loss) of approximately $23.0 million, net of tax, as the
effect of the change in accounting principle (transition adjustment) 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 $20.6 million and $17.1
million, net of tax, as a result of qualifying cash flow hedges whose hedged
transactions occurred during the years ended December 31, 2002 and 2001,
respectively. These losses were recorded in cost of gas. The Company estimates
that most of the December 31, 2002 unrealized gain balance of $2.2 million, net
of tax, will be reclassified from accumulated other comprehensive income (loss)
to earnings in 2003 as a decrease to realized gas cost if market prices remain
stable. As of December 31, 2002, all of the Company's cash flow hedges settle by
their terms before the end of 2005.
SCPC's tariffs include a purchased gas adjustment (PGA) clause that
provides for the recovery of actual gas costs incurred. The SCPSC has ruled that
the results of SCPC's hedging activities are to be included in the PGA. As such,
costs of related derivatives that SCPC utilizes to hedge its gas purchasing
activities are recoverable through its weighted average cost of gas calculation.
The offset to the change in fair value of these derivatives is recorded as a
regulatory asset or liability.
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 (loss), and was insignificant in 2002, 2001 and 2000.
Interest Rates
The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable and receive
fixed interest payments, and are designated as fair value hedges of certain debt
instruments. The Company may terminate a swap agreement, and may replace it with
a new swap also designated as a fair value hedge.
Payments received to terminate a swap are recorded as a basis adjustment
to long term debt, and are amortized as reductions to interest expense over the
term of the underlying debt. The fair value of interest rate swaps is reflected
within other deferred debits on the balance sheet. The fair value of the debt
that is hedged is recorded in long-term debt. Receipts or payments related to
the interest rate swaps are credited or charged to interest expense as incurred.
The Company received payments to terminate swaps totaling $29.3 million
and $6.5 million in 2002 and 2001, respectively. These amounts are being
amortized over the ten year term of the underlying debt they formerly hedged. At
December 31, 2002 the estimated fair value of the Company's swaps totaled $9.0
million related to combined notional amounts of $344.9 million.
12. COMMITMENTS AND CONTINGENCIES
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC mandated that SCE&G reinforce its Lake Murray
dam in order to comply with new federal safety standards and 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
approximately $275 million and be completed in 2005. Costs incurred through
December 31, 2002 totaled approximately $67 million.
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.
The Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on SCE&G
at present due to the "grandfathered" status of existing licensees that are
covered under the past act until such time as it is renewed.
SCE&G currently maintains policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric Insurance Limited. 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 $15.5 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
At SCE&G, site assessment and cleanup costs are recorded in deferred
debits and amortized with recovery provided through rates. Deferred amounts, net
of amounts previously recovered through rates and insurance settlements, totaled
$17.9 million at December 31, 2002. The deferral includes the estimated costs
associated with the following matters.
SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. SCE&G
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the
Calhoun Park 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 before 2006. SCE&G has spent approximately $2.2
million related to these sites, and expects to incur an additional $5.9 million.
Public Service Company of North Carolina, Incorporated
PSNC Energy 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 Energy's actual remediation
costs for these sites will depend on a number of factors, such as actual site
conditions, third-party claims and recoveries from other potentially responsible
parties (PRP). In September 2002 an allocation agreement was reached relieving
PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a
liability and associated regulatory asset of $7.8 million, which reflects the
estimated remaining liability at December 31, 2002. Amounts incurred to date
that have not been recovered through gas rates are approximately $1.2 million.
Management believes that all MGP cleanup costs will be recoverable through gas
rates.
D. Franchise Agreements
See Note 6 for a discussion of the electric and gas franchise agreements
between SCE&G and the cities of Columbia and Charleston.
E. Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of
SCANA filed suit against SCANA in South Carolina 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.
In 2001 the Company entered into, in the ordinary course of business, a
15 year take-and-pay contract with an unaffiliated natural gas supplier
(Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring
of 2004. In December 2002, as a result of the failure of Supplier and its
guarantor to meet contractual obligations related to credit support provisions,
the Company terminated the contract. Attempts to negotiate a new contract
between the parties were not successful. In February 2003, the Company received
notification from Supplier of its request for binding arbitration under the
original contract. The Company is confident of the propriety of its actions and
will vigorously pursue its position in such arbitration proceedings. The Company
further believes that the resolution of these claims will not have a material
adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without 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
2013. Rent expense totaled approximately $11.5 million, $12.1 million and $8.8
million in 2002, 2001 and 2000, respectively. Future minimum rental payments
under such leases are as follows:
Millions of dollars
2003 $15.9
2004 12.3
2005 10.6
2006 10.0
2007 9.7
Thereafter 17.3
------
$75.8
At December 31, 2002 minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$11.5 million.
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
2003 $1,249.2
2004 317.5
2005 145.5
2006 107.7
2007 93.0
Thereafter 604.8
$2,517.7
Forward contracts for natural gas purchases include customary
"make-whole" or default provisions, but are not considered to be "take-or-pay"
contracts.
13. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are described below. The accounting
policies of the segments are the same as those described in the summary of
significant accounting policies. The Company records intersegment sales and
transfers of electricity and gas based on rates established by the appropriate
regulatory authority. Nonregulated sales and transfers are recorded at current
market prices.
Electric Operations is 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 Energy, 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 Energy's operations cover 27
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 restructured
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 differ from
each other primarily based on their respective markets and customer type.
Disclosure of Reportable Segments
Millions of dollars
- ------------------------- ---------- ----------- ------------ ---------- ----------- ------------ -------- ------------ ------------
Electric Gas Gas Retail Energy Telecom All Adjustments/ Consolidated
Gas
2002 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ------------------------- ---------- ----------- ------------ ---------- ----------- ------------ -------- ------------ ------------
Customer Revenue $1,380 $653 $225 $380 $316 - $69 $(69) $2,954
Intersegment Revenue 613 1 254 - - - 6 (874) -
Operating Income 417 69 6 n/a n/a - - 22 514
Interest Expense 8 21 5 3 1 $11 1 149 199
Depreciation & Amortization 166 47 6 - 1 - 7 (7) 220
Income Tax Expense 3 13 - 6 (1) (92) 11 96 36
(Benefit)
Net Income (Loss) n/a n/a n/a 14 (172) 2 14 (142)
-
Segment Assets 5,567 1,459 318 128 53 380 74 (225) 7,754
Expenditures for Assets 625 68 17 - - - 15 (23) 702
Deferred Tax Assets 6 6 6 5 2 25 1 (51) -
- ---------------------------- ---------- ----------- ------------ ---------- ----------- ------------ -------- ----------------------
Millions of dollars
- ------------------------------------ ----------- ------------- ---------- ---------- ------------ -------- -----------------------
Electric Gas Gas Retail Energy Telecom All Adjustments/ Consolidated
Gas
2001 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ------------------------------------ ----------- ------------- ---------- ---------- ------------ -------- ------------ ------------
Customer Revenue $1,369 $793 $222 $454 $613 - $49 $(49) $3,451
Intersegment Revenue 576 1 256 - - - 8 (841) -
Operating Income 419 75 16 n/a n/a - - 18 528
Interest Expense 10 22 6 5 4 $23 2 151 223
Depreciation & Amortization 160 54 7 2 1 - 6 (6) 224
Income Tax Expense 3 18 4 3 (8) 169 4 112 305
(Benefit)
Net Income (Loss) n/a n/a n/a 7 4 314 240 539
(26)
Segment Assets 5,034 1,617 335 99 96 784 272 (415) 7,822
Expenditures for Assets 414 90 21 4 2 - 17 - 548
Deferred Tax Assets 6 - 4 5 6 - - (21) -
- ---------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------
Millions of dollars
- ------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ------------
Electric Gas Gas Retail Energy Telecom All Adjustments/ Consolidated
Gas
2000 Operations DistributionTransmission Marketing Marketing Investments Other Eliminations Total
- ------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ------------
Customer Revenue $1,344 $748 $250 $413 $679 - $41 $(42) $3,433
Intersegment Revenue 318 1 239 - - - 9 (567) -
Operating Income (Loss) 446 85 28 n/a n/a - - (5) 554
Interest Expense 13 20 4 4 2 $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 n/a 3 (3) (7) 1 256 250
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) -
- ---------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------
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 direct and indirect wholly owned subsidiaries of the Company.
These subsidiaries conduct nonregulated operations in energy-related and
telecommunications industries. None of these subsidiaries met any of the
quantitative thresholds for determining reportable segments in 2002, 2001 or
2000.
Management uses operating income to measure segment profitability for
regulated operations. For nonregulated operations management uses net income
(loss) 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 Energy 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 2002 and 2000, adjustments to net income and income tax
expense include the cumulative effects of the accounting changes 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 Energy 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.
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
2002 First Second Third Fourth
Millions of dollars, except per share amounts Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
Total operating revenues $822 $649 $694 $789 $2,954
Operating income 153 89 154 118 514
Income (loss) before cumulative effect of accounting change (72) 40 78 42 88
Cumulative effect of accounting change, net of taxes (1) (230) - - - (230)
Net income (loss) (302) 40 78 42 (142)
Basic and diluted earnings (loss) per share (2.88) .38 .74 .47 (1.34)
- -------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
- -------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
2001 First Second Third Fourth
Millions of dollars, except per share amounts 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
- -------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
(1) The cumulative effect of accounting change is attributable to the adoption
of SFAS 142. The amount of the cumulative effect was finalized in the fourth
quarter 2002 and, as prescribed in the standard, was recorded effective January
1, 2002. See Note 1G.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 90
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..........103
Item 8. Financial Statements and Supplementary Data.........................103
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) performance of SCANA Corporation's pension plan assets and the impact
on SCE&G's results of operations, (10) inflation, (11) changes in environmental
regulations and (12) 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
In South Carolina, electric restructuring efforts remain stalled, and
consideration of electric restructuring legislation is unlikely in 2003.
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. In view of the potential
for deregulation, SCE&G has continued efforts to renew franchise agreements with
municipalities within its current service area. Effective October 2002, SCE&G
secured a 30-year franchise to provide the City of Columbia, South Carolina,
with electric and natural gas services. Columbia is one of the largest cities in
SCE&G's service area. Previously, SCE&G reached franchise agreements with the
cities of North Charleston (franchise expires in 2021), Charleston (franchise
expires in 2026) and numerous other municipalities. In addition, in May 2001
SCE&G signed an electric supply contract with North Carolina Electric Membership
Corporation to supply 350 MW in each of 2004 and 2005 and 250 MW annually in
2006 through 2012. These energy sales are recallable for our native load, if
necessary.
At the federal level, energy legislation passed both houses of Congress
in 2002, though significant differences between the House and Senate versions
were not reconciled before the legislative session adjourned. Some of the more
stringent provisions of this legislation would have required, among other
things, that one percent of the electric energy sold by retail electric
suppliers, beginning in 2005, escalating to ten percent in 2019, be generated
from renewable energy resources. Renewable energy resources, as defined in some
versions of the legislation, would have excluded hydroelectric generation.
Substantial penalties would have been levied for failure to comply. Electric
cooperatives and municipal utilities would have been exempt from these
requirements. SCE&G expects similar legislation will be introduced in Congress
in 2003. SCE&G cannot predict whether such legislation will be enacted, and if
it is, the conditions it would impose on utilities.
In June 2002 implementation of GridSouth Transco LLC (GridSouth) was
suspended pending the issuance and evaluation of new FERC directives. In July
2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market
Design which proposes sweeping changes to the country's existing regulatory
framework governing transmission, open access and energy markets and will
attempt, in large measure, to standardize the national energy market. While it
is anticipated that significant change to the NOPR may occur and that
implementation, presently scheduled for September 2004, may be delayed, any
rules standardizing the markets may have a significant impact on SCE&G's access
to or cost of power for its native load customers and on SCE&G's marketing of
power outside its service territory. SCE&G is currently evaluating this NOPR to
determine what effect it will have on SCE&G's operations. Additional directives
from FERC are expected in 2003.
Gas Distribution
SCE&G has secured franchise agreements with several municipalities within
its current service areas to provide natural gas services. See previous
discussion at Electric Operations. Natural gas competes with electricity,
propane and heating oil to serve the heating and, to a lesser extent, the other
household energy needs of residential and small commercial customers. This
competition is generally based on price and convenience. Large commercial and
industrial customers often have the ability to switch from natural gas to an
alternate fuel, such as propane or fuel oil. Natural gas competes with these
alternate fuels based on price. As a result, any significant disparity between
supply and demand, either of natural gas or of alternate fuels, and due either
to production or delivery disruptions or other factors, will affect the price
and impact SCE&G's ability to retain large commercial and industrial customers
on a monthly basis.
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.
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
The estimated primary cash requirements for 2003 and the actual primary
cash requirements for 2002, 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 2003 2002
- -------------------------------------------------------------------------------
Property additions and construction
expenditures, net of AFC $619 $575
Nuclear fuel expenditures 30 13
Investments 20 9
Maturing obligations, redemptions and
sinking and purchase fund requirements 107 170
- -------------------------------------------------------------------------------
Total $776 $767
===============================================================================
Approximately 33% of total cash requirements was provided from internal
sources in 2002 as compared to 68% in 2001.
SCE&G's contractual cash obligations as of December 31, 2002 are
summarized as follows:
Contractual Cash Obligations
Less than After
December 31, 2002 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of dollars)
Long-term and short-term debt
(including interest) $3,525 $403 $680 $165 $2,277
Preferred stock sinking funds 10 1 2 1 6
Operating leases 68 13 30 18 7
Other commercial commitments 596 413 165 5 13
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 and the SEC. 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, 2002 the Bond Ratio
was 5.51. The Old Mortgage allows the issuance of Class A Bonds up to an
additional principal amount equal to (i) 70% of unfunded net property additions
(which unfunded net property additions totaled approximately $522 million at
December 31, 2002), (ii) retirements of Class A Bonds (which retirement credits
totaled $187.2 million at December 31, 2002), 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. At December 31, 2002 approximately $1.3 billion Class A Bonds were
on deposit with the Trustee of the New Mortgage and are available to support the
issuance of additional New Bonds. 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, 2002 the New Bond Ratio was 5.36.
SCE&G's Restated Articles of Incorporation (the Articles) 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, 2002 the Preferred Stock Ratio was 1.72.
The Articles also require the consent of at least a majority of the total
voting power of SCE&G's preferred stock before SCE&G may issue or assume any
unsecured indebtedness if, after such issue or assumption, the total principal
amount of all such unsecured indebtedness would exceed ten percent of the
aggregate principal amount of all of SCE&G's secured indebtedness and capital
and surplus (the ten percent test). No such consent is required to enter into
agreements for payment of principal, interest and premium for securities issued
for pollution control purposes. At December 31, 2002 the ten percent test would
have limited issuances of unsecured indebtedness to approximately $366.7
million. Unsecured indebtedness at December 31, 2002 totaled approximately
$127.6 million.
At December 31, 2002 SCE&G had $250 million of unused committed lines of
credit comprised of $175 million, expiring in 2003 and $75 million expiring in
2005. These lines of credit support the issuance of commercial paper. SCE&G's
commercial paper outstanding totaled $127.6 million and $114.7 million at
December 31, 2002 and 2001, respectively, at weighted average interest rates of
1.40% and 1.95%, respectively. On January 8, 2003 a credit agreement was reached
allowing SCE&G to share an existing $78 million SCANA uncommitted line of
credit. In addition, Fuel Company has a credit agreement for a maximum of $125
million expiring in 2003 with the full amount available at December 31, 2002.
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 totaled $50.1 million at
December 31, 2002 and 2001, at weighted average interest rates of 1.38% and
2.06%, respectively. This commercial paper and amounts outstanding under the
revolving credit agreement, if any, are guaranteed by SCE&G.
During the formation of GENCO in 1994, SCE&G's $36 million Berkeley
County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were
transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition,
holders of Berkeley Bonds may have recourse against SCE&G in the event of
default by GENCO.
Financing Transactions
The following financing transactions have occurred since January 1, 2002:
o On January 31, 2002 SCE&G issued $300 million of first mortgage
bonds having an annual interest rate of 6.625% 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 on March 11, 2002 its
$103.5 million First and Refunding Mortgage Bonds, 8 7/8% Series
due August 15, 2021.
o On October 17, 2002 SCE&G received an equity contribution of $150
million from SCANA, which was used to pay off short-term debt
primarily incurred as a result of SCE&G's construction program .
o On November 8, 2002 the South Carolina Jobs - Economic Development
Authority (JEDA) issued, and SCE&G borrowed the proceeds of, an
aggregate of $90.4 million principal amount of tax-exempt
Industrial revenue bonds (the Bonds). The Bonds bear interest at
rates ranging from 4.2% to 5.45%, with maturities ranging from 2012
to 2032. Proceeds from the Bonds were used to refund an aggregate
amount of $62.3 million principal amount of pollution control
revenue Bonds and to pay the costs of solid waste disposal
facilities at two of SCE&G's electric generating plants.
o On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15,
2033. The proceeds from the sale of these bonds were used to reduce
short-term debt and for general corporate purposes.
Other Information
SCE&G placed in service a $264 million gas turbine generator project in
Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn
natural gas to produce 341 MW of new electric generation and use exhaust heat to
replace coal-fired steam that powers two existing 75 MW turbines at the Urquhart
Generating Station.
In May 2002 SCE&G began construction of an 875 MW 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. The $450 million facility is
expected to begin commercial operation in mid-2004 and SCG Pipeline, Inc., an
affiliate, will transport natural gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam
in order to comply with new federal safety standards and 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
approximately $275 million and be completed in 2005. Costs incurred through
December 31, 2002 totaled approximately $67 million.
In 2002 SCE&G entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to
construct a roadbed for SCDOT in connection with the above Lake Murray dam
remediation project. The loan agreement provides for interest-free borrowings
for costs incurred not to exceed $59 million, with such borrowings being repaid
over ten years from the initial borrowing. At December 31, 2002 SCE&G had not
yet borrowed under the agreement.
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. SCE&G remains in compliance with these requirements. In 1998 the
EPA required the State of South Carolina, among other states, to modify its
state implementation plan (SIP) to address the issue of NOx pollution. The
State's SIP requires additional emissions reductions in 2004 and beyond.
Further, 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. To comply with these state and federal regulations, SCE&G
expects to incur capital expenditures of approximately $22 million over the
2003-2007 period to retrofit existing facilities, with increased operation and
maintenance costs of approximately $1 million per year. To meet compliance
requirements for the years 2008 through 2012, SCE&G anticipates additional
capital expenditures of approximately $70 million.
The EPA has undertaken an aggressive enforcement initiative against the
utilities 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. SCE&G 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.
SCE&G 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 SCE&G's financial position,
cash flows and results of operations.
The 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 of monitoring and
controlling thermal discharges and strategies for toxicity reduction in
wastewater streams. SCE&G is developing compliance plans for these initiatives.
Congress is expected to consider further amendments to the Clean Water Act in
2003. Such legislation may include limitations to mixing zones, the
implementation of technology-based standards for main condenser cooling water
including intake and discharge structures and toxicity-based standards. These
provisions, if passed, could have a material impact on the results of operations
and cash flows of SCE&G.
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 solely to regulated operations and are recorded in deferred
debits and amortized with recovery provided through rates. Deferred amounts, net
of amounts previously recovered through rates and insurance settlements, totaled
$17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. The
deferral includes the estimated costs associated with the following matters:
o SCE&G owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for
benzene contamination in the intermediate aquifer on surrounding
properties. SCE&G anticipates that the remaining remediation activities
will be completed in 2003, with certain monitoring and retreatment
activities continuing until 2007. As of December 31, 2002, SCE&G has
spent approximately $18.4 million to remediate the Calhoun Park 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
before 2006. SCE&G has spent approximately $2.2 million related to these
sites, and expects to incur an additional $5.9 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 $262 million and $109 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities of approximately $123 million and
$37 million, respectively, on its balance sheet at December 31, 2002.
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, 2002, SCE&G's net
investment in fossil and hydro and nuclear generation assets was approximately
$1,731 million and $546 million, respectively.
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in
retail electric rates of 5.8% which is designed to produce additional annual
revenues of approximately $70.7 million based on a test year calculation. The
SCPSC authorized a return on common equity of 12.45%. The new rates were
effective for service rendered on and after February 1, 2003. As a part of the
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may
increase depreciation of its Cope Generating Station in excess of amounts that
would be recorded based upon currently approved depreciation rates, 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.
On December 31, 2002 the SCPSC issued an order approving SCE&G's request
to capitalize the cost of fuel consumed in the production of test power for the
gas turbines installed at Urquhart Generating Station in 2002. As a result,
SCE&G transferred approximately $12.5 million from fuel used in electric
generation to electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for 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 2002. In January 2003 in
conjunction with the approval of the retail rate increase, the SCPSC approved
SCE&G's request to reduce the fuel component to 1.678 cents per KWh.
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, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001
$.728 November-December 2002 $.793 March-October 2001
$.596 November-December 2001
In March 2003 the SCPSC issued an order approving SCE&G's request for an
out-of-period adjustment to increase the cost of gas component of its rates for
natural gas service from .728 cents per therm to .928 cents per therm, effective
with the first billing cycle in March 2003.
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 2002, as a
result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of
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, 2002 of $17.9
million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will
pay the City $32 million over eight years in exchange for a 30-year electric and
gas franchise, has conveyed transit-related property and equipment to the City
and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City.
SCE&G will continue to operate the plant for the City until 2005. SCE&G will
also pay the Central Midlands Regional Transit Authority up to $3 million as
matching funds for Federal Transit Administration grants for the purchase of new
transit coaches and a new transit facility. The cost of the franchise agreement
is recorded in other regulatory assets.
REGULATORY MATTERS - FEDERAL
SCE&G's regulated business operations were impacted by FERC Order No.
2000 and other related initiatives of the FERC. Order No. 2000 required each
utility under FERC jurisdiction that operates an electric transmission system to
submit plans for the possible formation of a regional transmission organization.
In March 2001 FERC gave provisional approval to SCE&G and two other southeastern
electric utilities to establish GridSouth as an independent regional
transmission company, responsible for operating and planning the utilities'
combined transmission systems. In June 2002 GridSouth implementation was
suspended pending the issuance and evaluation of new FERC directives.
In July 2002 FERC issued a NOPR on Standard Market Design which proposes
sweeping changes to the country's existing regulatory framework governing
transmission, open access and energy markets and which will attempt, in large
measure, to standardize the national energy market. While it is anticipated that
significant changes to the NOPR may occur and that implementation, presently
scheduled for September 2004, may not occur for some time, any rules
standardizing the markets may have significant impact on SCE&G's access to or
cost of power for its native load customers and on SCE&G's marketing of power
outside its service territory. SCE&G is currently evaluating this NOPR to
determine what effect it will have on SCE&G's operations. Additional directives
from FERC are expected later in 2003.
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 financial condition or results of
operations.
SFAS 71 - SCE&G is subject to the provisions of SFAS 71, "Accounting for
the Effects of Certain Types of Regulation," which requires it to record certain
assets and liabilities that defer the recognition of expenses and revenues to
future periods as a result of being rate-regulated. At December 31, 2002 SCE&G
had recorded approximately $262 million and $109 million of regulatory assets
and liabilities, respectively, including amounts recorded for deferred income
tax assets and liabilities. Management believes the regulatory assets are
recoverable through rates. The 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. 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 SCE&G.
However, ultimate recovery is subject to SCPSC approval. In the future, as a
result of deregulation or other changes in the regulatory environment, SCE&G may
no longer meet the criteria for continued application of SFAS 71 and could be
required to write off its regulatory assets and liabilities. Such an event could
have a material adverse effect on the results of operations of SCE&G's Electric
Distribution and Gas Distribution segments in the period the write-off would be
recorded. It is not expected that cash flows or financial position would be
materially affected.
Certain of SCE&G's regulatory assets and liabilities arise from its
environmental assessment program, which identifies and evaluates 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. Regulatory
assets and liabilities related to environmental cleanup affect primarily the Gas
Distribution segment and are due to the costs associated with current and former
MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale
of energy are recorded when service is rendered or when energy is delivered to
customers. Because customers are billed on cycles which vary based on the timing
of the actual reading of their electric and gas meters, we record estimates for
unbilled revenues at the end of each reporting period. Such unbilled revenue
amounts reflect estimates of the amount of energy delivered to each customer
since the date of the last reading of their respective meters. Such unbilled
revenues reflect consideration of estimated usage by customer class, the effects
of different rate schedules, changes in weather and, where applicable, the
impact of weather normalization provisions of rate structures. The accrual of
unbilled revenues in this manner properly matches revenues and related costs. As
of December 31, 2002 and 2001, accounts receivable include unbilled revenues of
$43.9 million and $39.1 million, respectively. Total revenues for 2002 and 2001
were $1.68 billion and $1.72 billion, respectively.
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 is
depreciated as a component of plant cost in establishing rates for utility
services. SCE&G calculated AFC using composite rates of 7.8%, 8.8% and 8.1% for
2002, 2001 and 2000, 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. AFC primarily
affects the Electric Operations segment due to its capital-intensive
construction program, and to a lesser extent, AFC affects the Gas Distribution
segment. AFC represented approximately 9.4% of income before income taxes in
2002, 6.5% in 2001 and 1.7% in 2000. Because the equity component of AFC is not
taxable, increased AFC reduces SCE&G's effective tax rate. See Results of
Operations for additional discussion.
Provisions for Bad Debts and 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. SCE&G's Electric Distribution and Gas
Distribution segments have an established write-off history and a regulated
service area that enables it to reliably estimate its provision for bad debts.
Nuclear Decommissioning - Accounting for decommissioning costs for
nuclear power plants involves significant estimates related to costs to be
incurred many years in the future. Among the factors that could change SCE&G's
accounting estimates related to decommissioning costs are changes in technology,
changes in regulatory and environmental remediation requirements, as well as
changes in financial assumptions such as discount rates and timing of cash
flows. See also the discussion of SCE&G's adoption of SFAS 143, "Accounting for
Asset Retirement Obligations," below. Changes in any of these estimates could
significantly impact SCE&G's financial position and cash flows (although changes
in such estimates should be earnings-neutral, because these costs are expected
to be collected from ratepayers).
SCE&G's 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 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 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
are used to pay premiums on insurance policies on the lives of certain Company
and affiliate 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. Management intends for the fund, including earnings thereon, to
provide for all eventual decommissioning expenditures on an after-tax basis.
Pension Accounting - SCE&G follows SFAS 87, "Employers' Accounting for
Pensions," in accounting for its defined benefit pension plan. SCE&G's plan is
fully funded and as such, net pension income is reflected in the financial
statements (see Results of Operations). SFAS 87 requires the use of several
assumptions, the selection of which may have a large impact on the resulting
benefit recorded. Among the more sensitive assumptions are those surrounding
discount rates and returns on assets. Net pension income of $25.5 million
recorded in 2002 reflects the use of a 7.5% discount rate and an assumed 9.5%
long-term return on plan assets. SCE&G believes that these assumptions were, and
that the resulting pension income amount was, reasonable.
Due to poor performance in the stock market in recent years, SCE&G has
determined to adjust its assumed long-term return on assets to 9.25% for 2003.
Lower interest rates have also led to a reduction in the discount rate as of
December 31, 2002 to 6.5%. Had those assumptions been in place in 2002, net
pension income would have been reduced by approximately $5.2 million.
In determining the appropriate discount rate, SCE&G considers the market
indices of high-quality long-term fixed income securities. As such, SCE&G
selected the above discount rate of 6.5% as being within a reasonable range of
Moodys "Aa" interest rate as of December 31, 2002. This same discount rate was
also selected for determination of OPEB liabilities discussed below.
The following information with respect to pension assets should also be
noted:
SCE&G determines the fair value of substantially all of its pension
assets utilizing market quotes rather than utilizing any calculated values,
"market related" values or other modeling techniques. In developing the expected
long-term rate of return assumptions, SCE&G evaluated input from actuaries and
from pension fund investment advisors, including such advisors' review of the
plan's historical 10, 16 and 24 year cumulative actual returns of 10.15%, 10.80%
and 12.32%, respectively, which have all been in excess of related broad
indices. SCE&G anticipates that the investment managers will continue to
generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset
allocation of 80% with equity managers and 20% with fixed income managers. While
management believes that the asset allocation will return to those levels,
because of market fluctuations, the actual asset allocation as of December 31,
2002 was 70% with equity managers and 30% with fixed income managers. Management
regularly reviews such allocations and periodically rebalances the portfolio to
the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate
have significantly reduced the level of pension income, the pension trust has
been and remains adequately funded, and no contributions have been required
since 1997. As such, recent declines in pension income have had no impact on
SCE&G's cash flows. Based on stress testing performed by SCE&G's actuaries,
management does not anticipate the need to make pension contributions until at
least 2008.
Accounting for Postretirement Benefits other than Pensions - Similar to
its pension accounting, SCE&G follows SFAS 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," in accounting for its
postretirement medical and life insurance benefits. This plan is unfunded, so no
assumptions related to return on assets impact 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 7.5% and recorded a
net SFAS 106 cost of $13.6 million for 2002. Had the selected discount rate been
6.5%, the expense would have been approximately $0.9 million higher.
SFAS 143 - SFAS 143 provides guidance for recording and disclosing
liabilities related to the future obligations to retire assets (ARO). SFAS 143
applies to the legal obligation associated with the retirement of long-lived
tangible assets that result from acquisition, construction, development and
normal operations. SCE&G adopted SFAS 143 effective January 1, 2003. Because
such obligation relates solely to SCE&G's regulated electric operations,
adoption of SFAS 143 will have no impact on results of operations; however,
SCE&G will record an ARO of approximately $110 million, which exceeds the
previously recorded reserve for nuclear plant decommissioning of approximately
$87 million.
In addition to the ARO for Summer Station, SCE&G believes that there is
legal uncertainty as to the existence of environmental obligations associated
with certain transmission and distribution properties. SCE&G believes that any
ARO related to this type of property would be insignificant and, due to the
indeterminate life of the related assets, an ARO could not be reasonably
estimated.
SCE&G records cost of removal as a component of accumulated depreciation
for property that does not have an associated legal retirement obligation. As of
December 31, 2002, SCE&G estimates that approximately $225 million of its
accumulated depreciation balance is related to this regulatory liability.
OTHER MATTERS
Synthetic Fuel Investments
SCE&G holds two equity-method investments in partnerships involved in
converting coal to non-conventional fuel, the use of which fuel qualifies for
federal income tax credits. The aggregate investment in these partnerships as of
December 31, 2002 is approximately $2 million, and through December 31, 2002,
they had generated and passed through to SCE&G approximately $58 million in such
tax credits. Under a plan approved by the SCPSC, any tax credits generated and
ultimately passed through to SCE&G from synfuel produced and consumed by SCE&G
have been and will be deferred and will be applied to offset the capital costs
of projects required to comply with legislative or regulatory actions. See Note
1B of Notes to Consolidated Financial Statement.
Nuclear License Extension
In August 2002 SCE&G filed an application with the NRC for a 20-year
license extension for its Summer Station. If approved, the extension would allow
the plant to operate through 2042. SCE&G estimates that it will incur
approximately $12 million in costs related to the application process.
Claims and Litigation
SCE&G is engaged in various 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
2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000
- ------------------------------------------------ ------------- ----------------
Net income derived from:
Continuing operations $219.6 $221.9 $231.3
Cumulative effect of accounting
change, net of taxes - - 22.3
- ---------------------------------------------------------- -------------- -----
Net income $219.6 $221.9 $253.6
========================================================== ============== =====
Percent increase (decrease) in
net income 34.04% (1.04%) (12.50%)
========================================================== ============== =====
o 2002 vs 2001 Net income decreased primarily due to higher operations and
maintenance expenses of $30.4 million (including $10.1 million due to lower
pension income), higher property taxes of $6.5 million, and higher interest
expense of $4.7 million, which were partially offset by higher electric
margins of $37.3 million.
o 2001 vs 2000 Net income decreased primarily as a result of milder weather.
Pension Income
For the last several years, the market value of SCE&G's retirement plan
(pension) assets has exceeded the total actuarial present value of accumulated
plan benefits. However, pension income for 2002 decreased significantly compared
to 2001 and 2000, primarily as a result of a less favorable investment market.
Pension income during these periods, excluding amounts attributable to Santee
Cooper and affiliates (see Note 4) was recorded on SCE&G's financial statements
as follows:
Millions of dollars 2002 2001 2000
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Income Statement Impact:
Reduction in employee benefit costs $10.5 $20.7 $20.9
Increase in other income 11.2 12.7 12.9
Balance Sheet Impact:
Reduction in capital expenditures 3.1 5.9 5.7
Increase in amount due to Santee Cooper .7 1.8 2.0
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total Pension Income $25.5 $41.1 $41.5
==========================================================================
See also the discussion of pension accounting in Critical Accounting
Policies and New Accounting Standards.
Allowance for Funds Used During Construction (AFC)
SCE&G's financial statements include the effects of 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 9.4% of
income before income taxes in 2002, 6.5% in 2001 and 1.7% in 2000.
Dividends Declared
SCE&G's Board of Directors declared the following dividends on common
stock (all of which is held by SCANA) during 2002:
------------------- ------------------ -------------------- -----------------
Declaration Date Dividend Amount Quarter Ended Payment Date
------------------- ------------------ -------------------- -----------------
February 21, 2002 $34.0 million March 31, 2002 April 1, 2002
May 2, 2002 $38.0 million June 30, 2002 July 1, 2002
August 1, 2002 $40.5 million September 30, 2002 October 1, 2002
October 31, 2002 $40.5 million December 31, 2002 January 1, 2003
------------------- ------------------ -------------------- -----------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and
Fuel Company. Electric operations sales margins for 2002, 2001 and 2000,
excluding the cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000
- ---------------------------------------------- -------------- --------------
Operating revenues $1,384.8 $1,374.0 $1,343.8
Less: Fuel used in generation (257.5) (223.9) (231.6)
Purchased power (151.6) (233.9) (182.7)
- ---------------------------------------------- -------------- --------------
Margin $975.7 $916.2 $929.5
============================================== ============== ==============
o 2002 vs 2001 Margins increased $31.9 million due to more favorable
weather and $30.5 million due to customer growth. Fuel used in
generation increased and purchased power decreased due to completion
of the Urquhart Station repowering project in June 2002 and fewer
plant outages during 2002.
o 2001 vs 2000 Sales margin decreased $32.1 million due to milder
weather and $12.6 million due to the impact of the slowing economy.
These decreases were partially offset by $25.6 million from customer
growth.
Increases (decreases) from the prior year in MWh sales volume by classes
were as follows:
Classification (in thousands) 2002 % Change 2001 % Change
---------------------------------------------------- ------------ ------------- -------------
Residential 735.6 11.3% (170.5) (2.5%)
Commercial 370.3 5.9% (17.1) -
Industrial 158.0 2.5% (317.7) (4.8%)
Sales for resale (excluding interchange) 333.7 29.9% (108.3) (8.8%)
Other 1.1 0.2% (18.9) (3.4%)
---------------------------------------------------- -------------
Total territorial 1,598.7 7.7% (632.5) (3.0%)
NMST (1,441.7) (67.1%) 208.0 10.0%
---------------------------------------------------- -------------
Total 157.0 0.7% (424.5) (2.0%)
==================================================== ============ ============= =============
o 2002 vs 2001 Territorial sales volume increased primarily due to more
favorable weather. The decrease in NMST volumes reflects SCE&G's
recording of buy-resale transactions in Other Income in 2002.
o 2001 vs 2000 Territorial sales volume decreased primarily due to
milder weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of
SCE&G. Gas distribution sales margins for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000
--------------------------------------------- -------------- ---------------
Operating revenues $298.2 $341.0 $325.1
Less: Gas purchased for resale (211.1) (251.6) (233.8)
--------------------------------------------- -------------- ---------------
Margin $87.1 $89.4 $91.3
============================================= ============== ===============
Sales margin decreased slightly over the three-year period primarily as a
result of the slowing economy and increased competition with alternate fuels.
Increases (decreases) from the prior year in DT sales volume by classes,
including transportation gas were as follows:
Classification (in thousands) 2002 % Change 2001 % Change
- ---------------------------------------- --------------------------- ----------
Residential 985.9 8.8% (3,249.4) (22.4%)
Commercial 412.7 3.7% (1,511.4) (11.8%)
Industrial 1,637.3 11.4% (2,828.1) (16.5%)
Transportation gas (87.6) (3.6%) 375.4 18.0%
-- ------ --- -----
- -----------------------------
Total 2,948.3 7.5% (7,213.5) (15.5%)
===================================================== ============= ===========
o 2002 vs 2001 Residential and commercial sales volume increased
primarily due to more favorable weather. Industrial volumes increased
in 2002 after the volatility of the natural gas market in 2001 had
resulted in interruptible customers using their alternate fuel sources
during that year.
o 2001 vs 2000 Residential sales volumes decreased due to higher gas
prices. Industrial and transportation gas decreased due to the
volatility of the natural gas market resulted in interruptible
customers using alternate fuel sources.
Other Operating Expenses
Increases in other operating expenses were as follows:
Millions of dollars 2002 % Change 2001 % Change
- ----------------------------------------- ------------------------------------
Other operation and maintenance $50.9 16.1% $7.0 2.3%
Depreciation and amortization 7.1 4.4% 5.1 3.2%
Other taxes 10.0 10.1% 1.5 1.5%
- ----------------------------------------- ----------
Total $68.0 11.8% $13.6 2.4%
========================================= ====================================
o 2002 vs 2001 Other operation and maintenance expenses increased
primarily due to lower pension income of $10.1 million, increased
labor and benefits of $19.4 million, increased nuclear refueling
maintenance of $4.0 million, increased cost at Cogen South of $3.1
million, higher property insurance of $2.6 million, increased
amortization of environmental costs of $3.0 million and increased
storm damage expenses of $1.8 million. Depreciation and amortization
increased primarily due to completion of the Urquhart Station
repowering project in June 2002 of $4.8 million and normal net
property additions of $2.2 million. Other taxes increased primarily
due to increased property taxes.
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.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component
of AFC, were as follows:
Millions of dollars 2002 % Change 2001 % Change
- ----------------------------------------------------------------------------
Interest on long-term debt, net $9.1 8.1% $12.0 11.9%
Other interest expense 1.3 22.8% (2.4) (29.6%)
- ----------------------------------------- ----------
Total $10.4 8.8% $9.6 8.8%
============================================================================
Interest expense in 2002 increased by $11.9 million as a result of
increased borrowings, and was partially offset by $2.8 million as a result of
declining interest rates. Interest expense in 2001 increased as a result of
increased borrowings.
Income Taxes
Income taxes decreased approximately $10.1 million for the year 2002
compared to 2001 and decreased approximately $9.8 million for the year ended
2001 compared to 2000. Changes in income taxes are primarily due to changes in
operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The tables below provide information about long-term
debt issued by SCE&G which is sensitive to changes in interest rates. For debt
obligations the tables present principal cash flows and related weighted average
interest rates by expected maturity dates. Fair values for debt represent quoted
market prices.
December 31, 2002 Expected Maturity Date
Millions of dollars
Liabilities 2003 2004 2005 2006 2007 Thereafter Total Fair Value
- -------------------------------- ---------- --------- ----------- ----------- ------------ ------------- ------------ ------------
Long-Term Debt:
Fixed Rate ($) 144.0 138.4 188.4 169.1 38.2 1,180.6 1,858.7 1,882.1
Average Interest Rate (%) 6.37 7.44 7.35 8.49 6.74 6.81 7.03
December 31, 2001 Expected Maturity Date
Millions of dollars
Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value
- -------------------------------- ---------- --------- ----------- ----------- ------------ ------------- ------------ ------------
Long-Term Debt:
Fixed Rate ($) 129.7 123.9 173.9 154.7 1,561.0 1,542.9
27.6 951.2
Average Interest Rate (%) 7.52 7.40 8.66 7.33 7.33
6.73 6.37
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.............................................. 104
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001.......... 105
Consolidated Statements of Income for years ended December
31, 2002, 2001 and 2000 ............................................ 107
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 .................................. 108
Consolidated Statements of Capitalization as of December
31, 2002 and 2001...,............................................ 109
Consolidated Statements of Common Equity for the years
ended December 31, 2002, 2001 and 2000 ............................ 110
Notes to Consolidated Financial Statements............................ 111
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, 2002 and 2001 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, 2002. Our audits also included the financial statement schedule
listed in Part IV at Item 15. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with 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, 2002
and 2001 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002 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
Columbia, South Carolina
February 7, 2003
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------- ---------------- -------------------
December 31, (Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------------- ---------------- -------------------
Assets
Utility Plant (Note 5):
Electric $4,934 $4,563
Gas 439 425
Other 184 188
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total 5,557 5,176
Accumulated depreciation and amortization (1,912) (1,841)
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total 3,645 3,335
Construction work in progress 604 511
Nuclear fuel, net of accumulated amortization 38 45
- ------------------------------------------------------------------------------------- ---------------- -------------------
Utility Plant, Net 4,287 3,891
- ------------------------------------------------------------------------------------- ---------------- -------------------
Nonutility Property and Investments, Net 25 24
- ------------------------------------------------------------------------------------- ---------------- -------------------
Current Assets:
Cash and temporary investments (Note 10) 115 78
Receivables 245 212
Receivables - affiliated companies 2 4
Inventories (at average cost):
Fuel 48 39
Materials and supplies 53 48
Emission allowances 10 13
Prepayments 24 6
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total Current Assets 497 400
- ------------------------------------------------------------------------------------- ---------------- -------------------
Deferred Debits:
Environmental 18 24
Nuclear plant decommissioning fund 87 79
Pension asset, net (Note 4) 265 239
Due from affiliates - pension and postretirement benefits (Note 4) 18 15
Other regulatory assets 244 193
Other 111 97
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total Deferred Debits 743 647
- ------------------------------------------------------------------------------------- ---------------- -------------------
Total $5,552 $4,962
===================================================================================== ================ ===================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------- -------------------- --------------------
December 31, (Millions of dollars) 2002 2001
------------------------------------------------------------------------- -------------------- --------------------
Capitalization and Liabilities
Shareholders' Investment:
Common equity (Note 7) $1,966 $1,750
Preferred stock (Not subject to purchase or sinking funds) (Note 8) 106 106
------------------------------------------------------------------------- -------------------- --------------------
Total Shareholders' Investment 2,072 1,856
Preferred Stock, net (Subject to purchase or sinking funds) (Note 8) 9 10
Company-Obligated Mandatorily Redeemable Preferred Securities of the
Company'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 8) 50 50
Long-Term Debt, net (Notes 5 & 10) 1,534 1,412
------------------------------------------------------------------------- -------------------- --------------------
Total Capitalization 3,665 3,328
------------------------------------------------------------------------- -------------------- --------------------
Current Liabilities:
Short-term borrowings (Notes 6 & 10) 178 165
Current portion of long-term debt (Note 5) 144 28
Accounts payable 132 99
Accounts payable - affiliated companies 69 78
Customer deposits 22 19
Taxes accrued 93 80
Interest accrued 31 27
Dividends declared 42 42
Deferred income taxes, net (Note 10) 12 12
Other 24 8
------------------------------------------------------------------------- -------------------- --------------------
Total Current Liabilities 747 558
------------------------------------------------------------------------- -------------------- --------------------
Deferred Credits:
Deferred income taxes, net (Note 9) 610 599
Deferred investment tax credits (Note 9) 108 109
Reserve for nuclear plant decommissioning 87 79
Due to affiliates - pension and postretirement benefits (Note 4) 17 16
Postretirement benefits (Note 4) 131 122
Regulatory liabilities 109 81
Other 78 70
------------------------------------------------------------------------- -------------------- --------------------
Total Deferred Credits 1,140 1,076
------------------------------------------------------------------------- -------------------- --------------------
Commitments and Contingencies (Note 11) - -
------------------------------------------------------------------------- -------------------- --------------------
Total $5,552 $4,962
========================================================================= ==================== ====================
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
For the Years Ended December 31, 2002 2001 2000
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
(Millions of dollars)
Operating Revenues (Notes 2 & 3):
Electric $1,385 $1,374 $1,344
Gas 298 341 325
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Operating Revenues 1,683 1,715 1,669
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Operating Expenses:
Fuel used in electric generation 257 224 232
Purchased power (including affiliated purchases) 152 234 183
Gas purchased for resale 211 252 234
Other operation and maintenance 366 315 308
Depreciation and amortization 171 163 158
Other taxes 109 99 97
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Operating Expenses 1,266 1,287 1,212
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Operating Income 417 428 457
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Other Income:
Other Income, Including Allowance for Equity Funds Used
During Construction of $20, $13 and $2 36 26 14
Gain on sale of assets 1 4 2
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Total Other Income 37 30 16
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Interest Charges, Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 454 458 473
Interest Charges, Net of Allowance for Borrowed Funds Used
During Construction of $11, $9 and $4 118 109 105
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 336 349 368
Income Taxes (Note 9) 113 123 133
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 223 226 235
Dividend Requirement of Company - Obligated
Mandatorily Redeemable Preferred Securities 4 4 4
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Income Before Cumulative Effect of Accounting Change 219 222 231
Cumulative Effect of Accounting Change, net of taxes (Note 2) - - 22
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Net Income 219 222 253
Preferred Stock Cash Dividends (At stated rates) 7 7 7
- -------------------------------------------------------------------------- ------------------- --------------- ---------------- -
Earnings Available for Common Shareholder $212 $215 $246
========================================================================== =================== =============== ================ =
========================================================================== =================== =============== ================ =
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) 2002 2001 2000
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Operating Activities:
Net income $219 $222 $253
Adjustments to reconcile net income to net cash provided from
operating activities:
Cumulative effect of accounting change, net of taxes - - (22)
Depreciation and amortization 172 165 159
Amortization of nuclear fuel 20 16 16
Gain on sale of assets (1) (4) (2)
Allowance for funds used during construction (31) (22) (6)
Over (under) collection, fuel adjustment clause 10 (3) (34)
Changes in certain assets and liabilities:
(Increase) decrease in receivables (31) 71 (56)
(Increase) decrease inventories (11) (13) 8
(Increase) decrease in prepayments (18) (1) 3
(Increase) decrease in pension asset (26) (43) (43)
(Increase) decrease in other regulatory assets 4 1 15
Increase (decrease) in deferred income taxes, net 11 27 60
Increase (decrease) in other regulatory liabilities 39 22 6
Increase (decrease) in postretirement benefits 9 9 15
Increase (decrease) in accounts payable 24 16 50
Increase (decrease) in taxes accrued 13 29 (23)
Increase (decrease) in interest accrued 4 5 -
Changes in other assets (34) (19) (26)
Changes in other liabilities 37 (17) 6
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From Operating Activities 410 461 379
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (585) (427) (277)
Nonutility property additions (3) (2) (1)
Proceeds from sales of assets 2 3 2
Investments (9) (7) (1)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Investing Activities (595) (433) (277)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 295 149 148
Issuance of Industrial Revenue Bonds 87 - -
Capital contributions from parent 157 33 -
Repayments:
Mortgage Bonds (104) - (100)
Pollution Control Facilities Revenue Bonds (62) - -
Other long-term debt (3) (5) (4)
Retirement of preferred stock (1) - (1)
Dividend payments:
Common stock (153) (157) (131)
Preferred stock (7) (7) (7)
Short-term borrowings, net 13 (23) (25)
- ----------------------------------------------------------------------- ------------ ------------- -------------
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From (Used For) Financing Activities 222 (10) (120)
- ----------------------------------------------------------------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Temporary Investments 37 18 (18)
Cash and Temporary Investments, January 1 78 60 78
- ----------------------------------------------------------------------- ------------ ------------- -------------
Cash and Temporary Investments, December 31 $115 $78 $60
======================================================================= ============ ============= =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $11, $9 $114 $131 $102
and $4)
- Income taxes 60 70 97
Noncash Investing and Financing Activities:
Columbia Franchise Agreement $30 - -
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
December 31, (Millions of dollars) 2002 2001
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Total Common Equity (Note 7) $1,966 54% $1,750 53 %
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
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
Outstanding
Series 2002 2001 Redemption Price
------ ---- ---- ----------------
$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 8) 106 3% 106 3%
- ---------------------------------------------------------------------------------------- ------------- ------- ------------ -------
Cumulative Preferred Stock (Subject to purchase and sinking funds) $100 Par
Value - Authorized 1,550,000 shares; None outstanding in 2002 and 2001
$50 Par Value - Authorized 1,539,973 shares
Shares Outstanding
Series 2002 2001 Redemption Price
------ ---- ---- ----------------
4.50% & 4.60% (A) 18,849 22,449 $51.00 1 2
4.60% (B) 51,000 54,400 50.50 3 3
5.125% 65,000 66,000 51.00 3 3
6.00% 65,124 66,635 50.50 3 3
------------- -----------
Total 199,973 209,484
============= ===========
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 2002 and 2001
- ---------------------------------------------------------------------------------------- ------------- -------- ----------- --------
Total Preferred Stock (Subject to purchase or sinking funds) 10 11
Less: Current portion, including sinking funds requirements (1) (1)
- ---------------------------------------------------------------------------------------- ------------- -------- ----------- --------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 8 & 10) 9 -% 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 8) 50 1% 50 2%
- ---------------------------------------------------------------------------------------- ------------- -------- ----------- --------
Long-Term Debt (Notes 5 & 10):
Series Year of Maturity
First Mortgage Bonds: 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 150 150
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
6.63% 2032 300 -
First and Refunding Mortgage Bonds: 9% 2006 131 131
8 7/8% 2021 - 103
Pollution Control Facilities Revenue Bonds:
Fairfield County Series 1984 (6.50%) - 57
Orangeburg County Series 1994, due 2024 (5.70%) 30 30
Other 11 16
Industrial Revenue Bonds (4.2%-5.5%) 90 -
Franchise Agreements 17 4
Other 2 2
- --------------------------------------------------------------- ------------------------ ------------- -------- ----------- --------
Total Long-Term Debt 1,681 1,443
Less - Current maturities, including sinking fund (144) (28)
requirements
- Unamortized discount (3) (3)
- --------------------------------------------------------------- ------------------------ ------------- -------- ----------- --------
Total Long-Term Debt, Net 1,534 42% 1,412 42%
- --------------------------------------------------------------- ------------------------ ------------- -------- ----------- --------
Total Capitalization $3,665 100% $3,328 100%
=============================================================== ======================== ============= ======== =========== ========
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 (a) On Common Paid in Stock Retained Common
Shares Amount Stock Capital Expense Earnings Equity
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
Balance at December 31, 1999 40,296,147 $181 $395 $437 $(5) $550 $1,558
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
Earnings Available for Common Shareholder 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
Earnings Available for Common Shareholder 215 215
Cash Dividends Declared (155) (155)
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
Balance at December 31, 2001 40,296,147 181 395 470 (5) 709 1,750
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
Capital Contributions From Parent 157 157
Earnings Available for Common Shareholder 212 212
Cash Dividends Declared (153) (153)
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- ----------- -----------
- -------------------------------------------- ------------ ---------- --------------- ------------ ---------- -----------
Balance at December 31, 2002 40,296,147 $181 $395 $627 $(5) $768 $1,966
============================================ ============ ========== =============== ============ ========== =========== ===========
(a) $4.50 par value, authorized 50 million shares
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, 2002 and 2001, the
Company had approximately $29.6 million and $23.0 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, 2002 and
2001 the Company had approximately $9.0 million and $9.5 million, respectively,
payable to GENCO for unit power purchases. Such unit power purchases, which are
included in "Purchased power," amounted to approximately $109.5 million, $95.8
million and $100.2 million in 2002, 2001 and 2000, respectively.
Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $0.4 million,
$0.7 million and $1.1 million in 2002, 2001 and 2000, 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, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 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, 2002, approximately $262 million and $109 million
of regulatory assets and liabilities, respectively, as shown below.
December 31,
Million of dollars 2002 2001
- ------------------------------------------------------------- ---------------
- ------------------------------------------------------------- ---------------
Accumulated deferred income taxes, net $86 $86
Under- (over-) collections - Electric Fuel
and Gas Cost Adjustment Clause 50 60
Deferred environmental remediation costs 18 24
Deferred non-conventional fuel tax benefits, net (40) (17)
Storm damage reserve (32) (26)
Franchise agreements 64 -
Other 6 9
- ------------------------------------------------------------- ---------------
- ------------------------------------------------------------- ---------------
Total $152 $136
============================================================= ===============
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates fro which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under- (over-) collections - fuel adjustment clauses represent amounts
over- or under-collected from customers pursuant to the fuel adjustment clause
(electric customers) or gas cost adjustment (gas customers) as approved by the
Public Service Commission of South Carolina (SCPSC) during annual hearings (see
Note 1F).
Deferred environmental remediation costs represent costs associated with
the assessment and clean up of environmental sites at manufactured gas plant
sites currently or formerly owned by the Company. Costs incurred at sites owned
by the Company are being recovered through rates, and such costs, totaling
approximately $18 million are expected to be fully recovered by the end of 2005.
Deferred non-conventional fuel tax benefits represent the deferral of
partnership losses and other expenses, offset by the accumulated deferred income
tax credits associated with two of the Company's partnerships involved in
converting coal to alternate fuel. Under a plan approved by the SCPSC, any net
tax credits generated from non-conventional fuel produced and consumed by the
Company and ultimately passed through to the Company have been and will be
deferred and will be applied to offset the capital costs of projects required to
comply with legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account
capped at $50 million to be collected through rates over a ten-year period. The
accumulated storm damage reserve can be applied to offset actual storm damage
costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year electric
and gas franchise agreements with the cities of Charleston and Columbia, South
Carolina.
The SCPSC has reviewed and approved through specific orders most of the
items shown as regulatory assets. Other items represent costs which are not yet
approved for recovery by the SCPSC. 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 and Major Maintenance
Utility plant is stated substantially at original cost. The costs of
additions, renewals and betterments to utility plant, including direct labor,
material and indirect charges for engineering, supervision and an allowance for
funds used during construction, are added to utility plant accounts. The
original cost of utility property retired or otherwise disposed of is removed
from utility plant accounts and generally charged, 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 $962.4 million and $963.0 million as of December 31, 2002 and
2001, respectively. Accumulated depreciation associated with the Company's share
of Summer Station was approximately $417.9 million and $407.4 million as of
December 31, 2002 and 2001, respectively. The Company's share of the direct
expenses associated with operating Summer Station is included in "Other
operation and maintenance" expenses and totaled approximately $76.4 million for
the year ended December 31, 2002.
Planned major maintenance other than that related to nuclear outages is
expensed when incurred. The only major maintenance that is accrued in advance of
the time the costs are actually incurred is that related to the nuclear
refueling outages for which such accounting treatment and rate recovery of
expenses accrued thereunder has been approved by the SCPSC. Nuclear outages are
scheduled 18 months apart, and SCE&G begins accruing for each successive outage
immediately upon completion of the preceding outage. For the outage ended June
2002, the Company accrued approximately $0.5 million per month from January 2001
through June 2002 and is now accruing approximately $0.6 million per month for
its portion of the outage scheduled in October 2003. Total outage costs for the
planned outage in October 2003 are estimated to be approximately $17 million, of
which the Company will be responsible for approximately $11.3 million. As of
December 31, 2002, the Company had accrued $3.8 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 7.8%, 8.8% and
8.1% for 2002, 2001 and 2000, 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 $43.9 million and $39.1
million as of December 31, 2002 and 2001, 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 $25.3 million and $47.4 million
at December 31, 2002 and 2001, respectively, which amounts 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, 2002 and 2001 the Company had
undercollected through the gas cost recovery procedure approximately $24.6
million and $12.2 million, respectively, which amounts are also 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 2.93%, 2.98% and 2.98% for 2002, 2001 and 2000,
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 2002, 2001 and 2000) are used to pay premiums on
insurance policies on the lives of certain Company and affiliate 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. 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 cost in deferred
credits. See also discussion below related to the adoption of SFAS 143,
"Accounting for Asset Retirements Obligations," effective January 1, 2003.
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 $2.0 million and $2.4
million at December 31, 2002 and 2001, respectively, 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 and Other 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 2002 and
2001, capital contributions of approximately $7 million and $33 million,
respectively, were received by SCE&G under such provisions.
The Company records excise taxes billed and collected, as well as local
franchise and similar taxes as liabilities until they are remitted to the
respective taxing authority. As such, no excise taxes are included in revenues
or expenses in the statements of income.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt and
are being amortized as components of "Interest on long-term debt, net" over the
terms of the respective debt issues. Other issuance expense and gains or losses
on reacquired debt that is refinanced are recorded in other deferred debits or
credits and amortized over the term of the replacement debt.
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 solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates. Deferred
amounts, net of amounts previously recovered through rates and insurance
settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and
2001, respectively. The deferral includes the estimated costs associated with
the matters discussed in Note 11C.
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
In June 2001, FASB issued SFAS 143, which becomes effective for
financial statements issued for fiscal years beginning after June 15, 2002.
Accordingly, the Company adopted this standard effective January 1, 2003. SFAS
No. 143 applies to legal obligations associated with the retirement of tangible
long-lived assets (ARO) and requires the Company to recognize, as a liability,
the fair value of an ARO in the period in which it is incurred and to accrete
the liability to its present value in future periods.
The Company has determined that it should recognize an ARO related to
the decommissioning and dismantling of Summer Station and, effective January 1,
2003, will record an ARO of approximately $110 million, which amount exceeds the
previously recorded reserve for nuclear plant decommissioning of $87 million,
and a net capital asset of approximately $20 million. Due to the application of
SFAS 71, the difference between these amounts will be recorded in regulatory
accounts and will have no impact on the Company's results of operations or cash
flows.
In addition to the ARO for Summer Station, the Company believes that
there is legal uncertainty as to the existence of environmental obligations
associated with certain transmission and distribution properties. The Company
believes that any ARO related to this type of property would be insignificant
and, due to the indeterminate life of the related assets, an ARO could not be
reasonably estimated.
The Company records cost of removal as a component of accumulated
depreciation for property that does not have an associated legal retirement
obligation. As of December 31, 2002, the Company estimates that approximately
$225 million of its accumulated depreciation balance is related to this
regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," became 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.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treatment of gains or
losses from the early extinguishment of debt as extraordinary items unless such
early extinguishment meets the criteria of Accounting Principles Board Opinion
(APB) 30. The Company will adopt SFAS 145 effective January 1, 2003, and does
not expect that initial adoption will have any impact on the Company's results
of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2002.
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. 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.
3. RATE AND OTHER REGULATORY MATTERS
Electric
In January 2003 the SCPSC issued an order granting the Company an
increase in retail electric rates of 5.8% which is designed to produce
additional annual revenues of approximately $70.7 million based on a test year
calculation. The SCPSC authorized a return on common equity of 12.45%. The new
rates were effective for service rendered on and after February 1, 2003. As a
part of the order, the SCPSC extended through 2005 its approval of the
accelerated capital recovery plan for the Company's Cope Generating Station.
Under the plan, the Company may increase depreciation of its Cope Generating
Station in excess of amounts that would be recorded based upon currently
approved depreciation rates, 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.
In December 2002 the SCPSC issued an order approving the Company's
request to capitalize the cost of fuel consumed in the production of test power
for the gas turbines installed at Urquhart Generating Station in 2002. As a
result, the Company transferred approximately $12.5 million from fuel used in
electric generation to electric utility plant.
In May 2002 the SCPSC issued an order approving the Company's request to
increase the fuel component of rates charged to electric customers from 1.579
cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs
projected for the period May 2002 through April 2003. The increase also provided
continued recovery for 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 2002. In January 2003 in
conjunction with the approval of the above retail rate increase, the SCPSC
approved the Company's request to reduce the fuel component to 1.678 cents per
KWh. This reduction is effective for service rendered on or after February 1,
2003.
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, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001
$.728 November-December 2002 $.793 March-October 2001
$.596 November-December 2001
The SCPSC allows the Company'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 the Company's gas
operations that had previously been recorded in deferred debits. In October
2002, as a result of the annual review, the SCPSC reaffirmed the Company's
billing surcharge of 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, 2002 of $17.9 million.
Transit
On October 15, 2002 the Company transferred its transit system to the
City of Columbia, South Carolina (City). As part of the transfer agreement, the
Company will pay the City $32 million over eight years in exchange for a 30-year
electric and gas franchise, has conveyed transit-related property and equipment
to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to
the City. The Company will continue to operate the plant for the City until
2005. The Company will also pay the Central Midlands Regional Transit Authority
up to $3 million as matching funds for Federal Transit Administration grants for
the purchase of new transit coaches and a new transit facility. The cost of the
franchise agreement is recorded in other regulatory assets.
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 Energy's pension and postretirement benefit
plans were merged with SCANA's plans.
In connection with the joint ownership arrangements surrounding Summer
Station, as of December 31, 2002 and 2001 the Company has recorded within
deferred credits an $9.1 million and $8.4 million obligation, respectively, 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. As of December 31, 2002
and 2001, the Company has also recorded a $6.4 million and $6.0 million
receivable, respectively, 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 2002 2001 2002 2001 2000
---- ---- ---- ---- ----
2000
Service cost $9.0 $7.9 $ 8.3 $3.1 $3.0 $ 2.7
Interest cost 39.8 38.5 33.5 12.4 12.1 10.2
Expected return on assets (77.6) (83.5) (76.6) n/a n/a n/a
Prior service cost amortization 6.3 5.8 3.0 0.9 0.9 0.8
Actuarial (gain) loss (4.1) (12.8) (12.2) 1.1 0.7 -
Transition amount amortization 0.8 0.8 0.8 0.8 0.8 0.8
Amount attributable to Company affiliates 0.3 2.2 1.7 (4.7) (3.1) (1.6)
---- --- ---- ---- -------- -------- -------- --------
Net periodic benefit (income) cost $(25.5) $(41.1) $(41.5) $13.6 $14.4 $12.9
======= ====== ====== ===== ===== =====
Assumptions
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
As of December 31, 2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
Discount rate 6.5% 7.5% 8.0% 6.5% 7.5% 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 2002 2001 2002 2001
---- ---- ---- ----
Benefit obligation, January 1 $530.8 $479.3 $166.7 $139.0
Service cost 9.1 7.9 3.1 3.0
Interest cost 39.8 38.5 12.4 12.1
Plan participants' contributions - - 0.9 0.5
Plan amendment - 21.5 - 1.2
Actuarial loss 50.6 19.6 10.8 20.1
Benefits paid (34.7) (36.0) (10.5) (9.2)
-- ----- -- ----- --- ----- ---- ----
Benefit obligation, December 31 $595.6 $530.8 $183.4 $166.7
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
----------------------------------------------------
Millions of dollars 2002 2001
---- ----
Fair value of plan assets, January 1 $831.6 $894.3
Actual return on plan assets (130.0) (26.7)
Benefits paid (34.7) (36.0)
--- ----- -- -----
Fair value of plan assets, December 31 $666.9 $831.6
====== ======
Funded Status of Plans
Retirement Benefits Other Postretirement
Benefits
------------------------ -----------------------------
Millions of dollars 2002 2001 2002 2001
---- ---- ---- ----
Funded status, December 31 $71.3 $300.8 $(183.4) $(166.7)
Unrecognized actuarial (gain) loss 107.5 (155.0) 42.2 32.5
Unrecognized prior service cost 83.1 89.4 3.9 4.8
Unrecognized net transition obligation 3.1 4.0 6.6
------ --- --------- ------ ---
7.4
Net asset (liability) recognized in Consolidated Balance $265.0 $239.2 $(130.7) $(122.0)
====== ====== = ======== =========
Sheet
Health Care Trends
The determination of net periodic other postretirement health care benefit cost
is based on the following assumptions:
2002 2001 2000
- -------------------------------------------------------- --------- ----------
Health care cost trend rate 10.0% 8.5% 7.5%
Ultimate health care cost trend rate 5.0% 5.0% 5.5%
Year achieved 2011 2009 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 1.4 (1.7)
Due to poor performance in the stock market in recent years, the Company
has determined to adjust its long-term expected return on assets to 9.25% for
2003. In developing the expected long-term rate of return assumptions,
management evaluated the plan's historical cumulative actual returns over
several periods, which have all been in excess of related broad indices, and
management anticipates that the plan's investment managers will continue to
generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset
allocation of 80% with equity managers and 20% with fixed income managers. While
the Company believes that the asset allocation will return to those levels,
because of market fluctuations, the actual asset allocation as of December 31,
2002 was 70% with equity managers and 30% with fixed income managers. Management
regularly reviews such allocations and periodically rebalances the portfolio to
our targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate
have significantly reduced the level of pension income, the pension trust has
been and remains adequately funded, and no contributions have been required
since 1997. As such, recent declines in pension income have had no impact on the
Company's cash flows.
5. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2003 through 2007 are summarized as follows:
- ---------------- ----------------- ------------------ -----------------
Year Amount Year Amount
- ---------------- ----------------- ------------------ -----------------
(Millions of dollars)
2003 $144.0 2006 $169.1
2004 138.4 2007 38.2
2005 188.4
- ---------------- ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt payable in 2003 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.
In 2002 the Company entered into an agreement with the South Carolina
Transportation Infrastructure Bank (the Bank) and the South Carolina Department
of Transportation (SCDOT) that allows the Company to borrow funds from the Bank
to construct a roadbed for SCDOT in connection with the Lake Murray dam
remediation project. The loan agreement provides for interest-free borrowings
for costs incurred not to exceed $59 million, with such borrowings being repaid
over ten years from the initial borrowing. At December 31, 2002 the Company had
not yet borrowed under the agreement
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 has paid the City $25 million over seven years
(1996-2002) and donated to the City the existing transit assets in Charleston.
On October 15, 2002 SCE&G transferred its transit system to the City of
Columbia. As part of the transfer agreement, the Company will pay the City $32
million over eight years (2002-2009) in exchange for a 30-year electric and gas
franchise, has conveyed transit-related property and equipment to the City and
has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. The
Company will continue to operate the plant for the City until 2005.
The Company has a three-year revolving line of credit totaling $75
million, expiring in 2005, 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.
On January 23, 2003 the Company issued $200 million First Mortgage Bonds
having an annual interest rate of 5.80% and maturing on January 15, 2033. The
proceeds from the sale of these bonds were used to reduce short-term debt and
for general corporate purposes.
During the formation of GENCO in 1994, the Company's $36 million Berkeley
County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were
transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition,
holders of Berkeley Bonds may have recourse against the Company in the event of
default by GENCO.
Substantially all utility plant is pledged as collateral in connection with
long-term debt.
6. SHORT-TERM BORROWINGS
Details of lines of credit and short-term borrowings at December 31, 2002
and 2001, are as follows:
Millions of dollars 2002 2001
- -------------------------------------------------------------- ---------------
Lines of credit $300.0 $300.0
Unused lines of credit $300.0 $300.0
Short-term borrowings outstanding
Commercial paper (270 or fewer days) $177.7 $164.8
Weighted average interest rate 1.40% 1.97%
The Company pays fees to banks as compensation for committed lines of
credit.
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 16, 2003. 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 $50.1
million at December 31, 2002 and 2001, respectively, at weighted average
interest rates of 1.38% and 2.06%, respectively.
The Company's commercial paper outstanding totaled $127.6 million and
$114.7 million at December 31, 2002 and 2001, at weighted average interest rates
of 1.40% and 1.95%, respectively.
7. RETAINED EARNINGS
The Company's Restated Articles of Incorporation 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, 2002 approximately $41 million of retained earnings were
restricted by this requirement as to payment of cash dividends on common stock.
8. PREFERRED STOCK
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 2003 through 2007 is $2.7 million. The call
premium of the respective series of preferred stock in no case exceeds the
amount of the annual dividend.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 2002, 2001 and 2000 are summarized as follows:
Number of Shares Millions of Dollars
- -------------------------------------------------------- -----------------------
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
Shares Redeemed - $50 par value (9,511) (0.5)
- -------------------------------------------------------- -----------------------
Balance at December 31, 2002 199,973 10.0
======================================================== =======================
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% 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 a like amount of its 7.55%
Junior Subordinated Debentures due September 30, 2027. The sole asset of the
Trust is such Junior Subordinated Debentures of the Company. Accordingly, no
financial statements of the Trust are presented. The financial statements of the
Trust are consolidated in the financial statements of the Company. 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.
The preferred securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55% 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. 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.
9. INCOME TAXES
Total income tax expense attributable to income (before cumulative effect
of accounting change) for 2002, 2001 and 2000 is as follows:
Millions of dollars 2002 2001 2000
- -------------------------------------------------------------- ----------------- -----------------
Current taxes:
Federal $60.4 $83.8 $78.4
State 8.3 10.2 7.8
- -------------------------------------------------------------- ----------------- -----------------
- -------------------------------------------------------------- ----------------- -----------------
Total current taxes 68.7 94.0 86.2
- -------------------------------------------------------------- ----------------- -----------------
- -------------------------------------------------------------- ----------------- -----------------
Deferred taxes, net:
Federal 12.6 8.7 31.8
State 2.0 1.6 5.2
- -------------------------------------------------------------- ----------------- -----------------
- -------------------------------------------------------------- ----------------- -----------------
Total deferred taxes 14.6 10.3 37.0
- -------------------------------------------------------------- ----------------- -----------------
- -------------------------------------------------------------- ----------------- -----------------
Investment tax credits:
Deferred - State 5.0 5.0 5.0
Amortization of amounts deferred - State (1.7) (1.5) (1.3)
Amortization of amounts deferred - Federal (3.2) (3.2) (3.2)
- -------------------------------------------------------------- ----------------- -----------------
Total investment tax credits 0.1 0.3 0.5
- -------------------------------------------------------------- ----------------- -----------------
Non-conventional fuel tax credits:
Deferred - Federal 29.8 18.7 9.4
- -------------------------------------------------------------- ----------------- -----------------
Total income tax expense $113.2 $123.3 $133.1
============================================================== ================= =================
The difference between actual income tax expense and the amount calculated
from the application of the statutory 35% federal income tax rate to pre-tax
income before cumulative effect of accounting change is reconciled as follows:
Millions of dollars 2002 2001
2000
- ---------------------------------------------------------------- ----------------- ----------------- ------------------
Income before cumulative effect of accounting change $212.3 $214.5 $223.9
Total income tax expense:
Charged to operating expense 106.0 112.8 123.8
Charged to other items 7.1 10.5 9.3
Preferred stock dividends 11.2 11.2 11.2
- ---------------------------------------------------------------- ----------------- ----------------- ------------------
Total pre-tax income $336.6 $349.0 $368.2
================================================================ ================= ================= ==================
================================================================ ================= ================= ==================
Income taxes on above at statutory federal income tax rate $117.8 $122.2 $128.9
Increases (decreases) attributed to:
State income taxes (less federal income tax effect) 8.8 9.9 10.9
Allowance for equity funds using during construction (6.9) (4.7) (0.8)
Amortization of federal investment tax credits (3.2) (3.2) (3.2)
Other differences, net (3.3) (0.9) (2.7)
- ---------------------------------------------------------------- ----------------- ----------------- ------------------
- ---------------------------------------------------------------- ----------------- ----------------- ------------------
Total income tax expense $113.2 $123.3 $133.1
================================================================ ================= ================= ==================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $622.5 million at December 31, 2002 and
$611.3 million at December 31, 2001 (see Note 1I), are as follows:
Millions of dollars 2002 2001
- --------------------------------------------------------------- ----------------
Deferred tax assets:
Nondeductible reserves $59.1 $54.5
Unamortized investment tax credits 56.1 56.7
Deferred compensation 21.0 22.9
Cycle billing 6.3 10.6
Other 6.4 6.2
- --------------------------------------------------------------- ----------------
Total deferred tax assets 148.9 150.9
- --------------------------------------------------------------- ----------------
Deferred tax liabilities:
Property, plant and equipment 644.9 647.6
Pension plan benefit income 93.0 81.1
Deferred fuel costs 19.1 22.8
Other 14.4 10.7
- --------------------------------------------------------------- ----------------
Total deferred tax liabilities 771.4 762.2
- --------------------------------------------------------------- ----------------
Net deferred tax liability $622.5 $611.3
=============================================================== ================
The Internal Revenue Service has examined and closed consolidated federal
income tax returns of SCANA through 1997 and is currently examining SCANA's
1998, 1999 and 2000 federal returns. 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.
10. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2002 and 2001 are as follows:
Millions of dollars 2002 2001
---------------------------------------------------------- ---------------------- --------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
---------------------------------------------------------- ----------- ------------ ------------ -----------
Assets:
Cash and temporary cash investments $115.3 $115.3 $77.9 $77.9
Investments 5.5 5.5 6.5 6.5
Liabilities:
Short-term borrowings 177.7 177.7 164.8 164.8
Long-term debt 1,677.8 1,882.1 1,440.0 1,542.9
Preferred stock (subject to purchase or sinking funds) 10.0 8.6 10.4 8.5
---------------------------------------------------------- ----------- ------------ ------------ -----------
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. Early
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.
11. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC mandated that the Company reinforce its Lake
Murray dam in order to comply with new federal safety standards and 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
approximately $275 million and be completed in 2005. Costs incurred through
December 31, 2002 totaled approximately $67 million.
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 Price-Anderson Indemnification Act expired in August 2002, but is
expected to renew with only modest changes in 2003. This has no impact on the
Company at present due to the "grandfathered" status of existing licensees that
are covered under the past act until such time as it is renewed.
The Company currently maintains policies (for itself and on behalf of
Santee Cooper) with Nuclear Electric Insurance Limited. 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 $15.5 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
At the Company, site assessment and cleanup costs are recorded in
deferred debits and amortized with recovery provided through rates. Deferred
amounts, net of amounts previously recovered through rates and insurance
settlements, totaled $17.9 million at December 31, 2002. The deferral includes
the estimated costs associated with the following matters.
The Company owns a decommissioned MGP site in the Calhoun Park area of
Charleston, South Carolina. The site is currently being remediated for benzene
contamination in the intermediate aquifer on surrounding properties. The Company
anticipates that the remaining remediation activities will be completed in 2003,
with certain monitoring and retreatment activities continuing until 2007. As of
December 31, 2002, the Company has spent approximately $18.4 million to
remediate the Calhoun Park 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 before 2006. The Company has
spent approximately $2.2 million related to these sites, and expects to incur an
additional $5.9 million.
D. Franchise Agreements
See Note 5 for a discussion of the electric and gas franchise agreements
between the Company and the cities of Columbia and 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 $9.3 million, $9.0 million and $5.9
million in 2002, 2001 and 2000, respectively. Future minimum rental payments
under such leases are as follows:
Millions of dollars
2003 $12.5
2004 10.5
2005 9.6
2006 9.6
2007 9.4
Thereafter 16.9
-----
$68.5
At December 31, 2002 minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$11.3 million.
G. Purchase Commitments
Purchase commitments for coal supply and other contracts are as follows:
Millions of dollars
2003 $413.2
2004 159.7
2005 2.8
2006 2.7
2007 2.7
Thereafter 15.2
-------
$596.3
12. 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
2002 Operations Distribution Other Eliminations Total
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
Customer Revenue $1,385 $298 - - $1,683
Intersegment Revenue 216 2 - $(218) -
Operating Income (Loss) 403 15 - (1) 417
Interest Expense 2 n/a $4 112 118
Depreciation & Amortization 159 12 - - 171
Segment Assets 5,567 445 - (460) 5,552
Expenditures for Assets 602 19 - (25) 596
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
Millions of dollars
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
Electric Gas All Adjustments/ Consolidated
2001 Operations Distribution Other Eliminations Total
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
Customer Revenue $1,374 $341 - - $1,715
Intersegment Revenue 212 - - $(212) -
Operating Income (Loss) 405 26 - (3) 428
Interest Expense 3 n/a $4 102 109
Depreciation & Amortization 151 12 - - 163
Segment Assets 5,034 428 - (500) 4,962
Expenditures for Assets 409 16 - 4 429
- ---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
Millions of dollars
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
Electric Gas All Adjustments/ Consolidated
2000 Operations Distribution Other Eliminations Total
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
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
- --------------------------------- ------------ --------------- ---------------- ----------------- ------------------
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. In accordance with SFAS 109, the Company nets deferred tax assets
and deferred tax liabilities for reporting purposes. For 2000, adjustments to
net income include the cumulative effect of the accounting change described in
Note 2.
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.
Interest Expense is adjusted to include the totals from the Company
that are not allocated to the segments and to eliminate inter-segment charges.
Deferred Tax Assets are not allocated to reportable segments, and are included
in deferred credits, net, on the balance sheet.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of dollars
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
First Second Third Fourth
2002 Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Total operating revenues $411 $403 $472 $397 $1,683
Operating income 99 79 155 84 417
Net income 52 40 86 41 219
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Million of dollars
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
First Second Third Fourth
2001 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
- -------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
PUBLIC SERVICE COMPANY
OF NORTH CAROLINA, INCORPORATED
Item 7. Management's Narrative Analysis of Results of Operations....130
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...134
Item 8. Financial Statements and Supplementary Data..................135
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 Energy'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 Energy's accounting policies, (8) weather
conditions, especially in areas served by PSNC Energy, (9) performance of SCANA
Corporation's pension plan asset and its impact on PSNC Energy's results of
operations, (10) inflation, (11) changes in environmental regulations, and (12)
the other risks and uncertainties described from time to time in PSNC Energy's
periodic reports filed with the SEC. PSNC Energy disclaims any obligation to
update any forward-looking statements.
Net Income (Loss)
Net income (loss) for the years ended December 31, 2002 and 2001 was as
follows:
Millions of dollars 2002 2001
- --------------------------------------------------------------- ---------------
Net income derived from:
Continuing operations $22.6 $14.7
Cumulative effect of accounting change (229.6) -
- --------------------------------------------------------------- ---------------
Net income (loss) $(207.0) $14.7
=============================================================== ===============
Net income from continuing operations increased approximately $7.9
million, due to reduced amortization expense of $13.3 million and reduced
interest expense of $0.4 million, which was partially offset by increased
depreciation of $3.1 million, reduced other income of $1.7 million, higher
operating expenses of $0.7 million and reduced margin of $0.4 million.
In connection with the implementation of SFAS 142, the Company
performed a valuation analysis of its acquisition adjustment using an
independent appraisal. The analysis indicated that the carrying amount of the
acquisition adjustment exceeded its fair value by $230 million. As a result,
PSNC Energy recorded an impairment charge of $230 million in the fourth quarter
of 2002. The charge is presented on the Consolidated Statements of Operations as
the Cumulative Effect of an Accounting Change.
The nature of PSNC Energy's business is seasonal. The quarters ending
March 31 and December 31 are generally PSNC Energy's most profitable quarters
due to increased demand for natural gas related to space heating requirements.
PSNC Energy's Board of Directors authorized payment of capital
distributions to SCANA as follows:
Declaration Date Distribution Amount Quarter Ended Payment Date
February 21, 2002 $5.0 million March 31, 2002 April 1, 2002
May 2, 2002 $4.0 million June 30, 2002 July 1, 2002
August 1, 2002 $5.5 million September 30, 2002 October 1, 2002
October 31, 2002 $5.5 million December 31, 2002 January 1, 2003
Gas Distribution
Gas distribution sales margins for 2002 and 2001 were as follows:
Millions of dollars 2002 2001 Change % Change
- -----------------------------------------------------------------------------
Operating revenues $355.7 $452.6 $(96.9) (21.4%)
Less: Cost of gas (189.9) (286.1) 96.2 33.6%
- --------------------------------------------------------
Gross margin $165.8 $166.5 $(0.7) (0.4%)
=============================================================================
Gas distribution sales margin for the year ended December 31, 2002
decreased primarily due to lower natural gas usage of $1.3 million, a reduction
in rates in August 2001 related to the acquisition of PSNC Energy by SCANA of
$0.7 million, and lower other operating revenues of $0.6 million. The decrease
was partially offset by customer growth of $2.3 million. In addition to these
changes affecting margins, revenues and cost of gas also decreased in 2002
because of lower commodity natural gas prices.
Operation and Maintenance Expenses
The $1.1 million increase in operation and maintenance expenses from
2001 is primarily due to increased customer billing and other administrative
costs of $3.6 million and increased labor costs of $0.5 million, which was
partially offset by lower bad debt expense of $2.8 million.
Depreciation and Amortization Expenses
Depreciation and amortization expenses decreased $8.2 million primarily
due to implementation of SFAS 142 which resulted in the elimination of $13.3
million of amortization expense related to goodwill, which was partially offset
by increases for normal property additions of $5.1 million.
Other Income
Other income decreased $2.8 million for the year ended December 31,
2002 as compared to the same period in 2001 primarily due to reduced interest
income of $1.5 million, an increased provision for bad debt for merchandise and
jobbing of $0.6 million, lower equity method affiliate income of $0.3 million
and other of $0.4 million.
Interest Expense
Interest expense decreased $0.6 million over 2001 due to declining
interest rates.
Capital Expansion Program and Liquidity Matters
PSNC Energy's capital expansion program includes the construction of
lines, systems and facilities and the purchase of related equipment. PSNC
Energy's 2003 construction budget is approximately $46.7 million, compared to
actual construction expenditures for 2002 of $47.8 million.
For the years 2004-2007, PSNC Energy has an aggregate of $17.1 million
of long-term debt maturing. These obligations and other commitments are
tabulated below.
Contractual Cash Obligations
Less than After
December 31, 2002 Total 1year 1-3 years 4-5 years 5 years
- ----------------- ----- ----- --------- --------- -------
(Millions of dollars)
Long-term and short-term debt
(including interest) $585 $59 $71 $44 $411
Operating leases $ 1 - $ 1 - -
Other commercial commitments $276 $175 $101 - -
Included in other commercial commitments are estimated obligations under
forward contracts for natural gas purchases. Many of these forward contracts for
natural gas purchases include customary "make-whole" or default provisions, but
are not considered to be "take-or-pay" contracts. Certain of these contracts
relate to regulated gas businesses; therefore, the effects of such contracts on
gas costs are reflected in gas rates.
On January 2, 2003 the NCUC approved PSNC Energy's request to increase
the benchmark cost of gas from $.410 to $.460 per therm effective for service
rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC
Energy's request to increase the benchmark cost of gas from $.460 to $.595 per
therm effective March 1, 2003.
Financing Limits and Related Matters
PSNC Energy'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 and the SEC. The Indenture under
which these securities are issued contains no specific limit on the amount which
may be issued.
PSNC Energy finances its operations and capital needs through short-term
and long-term borrowings, including, from time to time, advances from SCANA. At
December 31, 2002 PSNC Energy had $125 million unused committed lines of credit,
expiring in 2003, under a credit agreement supporting the issuance of commercial
paper. PSNC Energy had total commercial paper outstanding of $31.1 million at
December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had
no commercial paper outstanding at December 31, 2001.
PSNC Energy has two interest rate swap agreements to pay variable rates
and receive fixed rates on a combined notional amount of $40.6 million at
December 31, 2002. (See Note 10 of Notes to Consolidated Financial Statements.)
PSNC Energy utilizes no off-balance sheet financings or similar arrangements
other than incidental operating leases, generally for office furniture and
equipment.
Competition
Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the other household energy needs of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane or
fuel oil. Natural gas competes with these alternate fuels based on price. As a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact PSNC Energy's ability to
retain large commercial and industrial customers on a monthly basis.
The NCUC has approved a rate structure that allows PSNC Energy 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 Energy anticipates that the need to negotiate reduced
rates with these customers will continue.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of PSNC Energy's accounting policies which
are new or most critical in terms of reporting financial conditions or results
of operations.
SFAS 71 - PSNC Energy is subject to the provisions of SFAS 71,
"Accounting for the Effects of Certain Types of Regulation," which requires it
to record certain assets and liabilities that defer the recognition of expenses
and revenues to future periods as a result of being rate-regulated. At December
31, 2002 PSNC Energy had recorded approximately $20 million and $1 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities. Management believes the regulatory
assets are recoverable through rates. The NCUC 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. 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 PSNC Energy. However, ultimate recovery is subject to NCUC approval.
In the future, as a result of deregulation or other changes in the regulatory
environment, PSNC Energy may no longer meet the criteria for continued
application of SFAS 71 and could be required to write off its regulatory assets
and liabilities. Such an event could have a material adverse effect on the
results of operations of PSNC Energy's Gas Distribution segment in the period
the write-off would be recorded. It is not expected that cash flows or financial
position would be materially affected.
Certain of PSNC Energy's regulatory assets and liabilities arise from
its environmental assessment program, which identifies and evaluates 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. Regulatory
assets and liabilities related to environmental cleanup affect primarily the Gas
Distribution segment and are due to the costs associated with current and former
MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale
of energy are recorded when service is rendered or when energy is delivered to
customers. Because customers are billed on cycles which vary based on the timing
of the actual reading of their gas meters, we record estimates for unbilled
revenues at the end of each reporting period. Such unbilled revenue amounts
reflect estimates of the amount of gas delivered to each customer since the date
of the last reading of their respective meters. Such unbilled revenues reflect
consideration of estimated usage by customer class, the effects of different
rate schedules, changes in weather and, where applicable, the impact of weather
normalization provisions of rate structures. The accrual of unbilled revenues in
this manner properly matches revenues and related costs. As of December 31, 2002
and 2001, accounts receivable include unbilled revenues of $27.7 million and
$20.2 million. Total revenues for 2002 and 2001 were $355.7 million and $452.6
million.
SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and Other
Intangible Assets," SCANA Corporation performed a valuation analysis of its
investment in PSNC Energy (Gas Distribution segment) using an independent
appraisal. SCANA obtained an independent appraisal for its initial valuation.
The independent appraisal made various assumptions related to cash flow
projections, discount rates, weighted average cost of capital and market
multiples for comparable companies. The analysis indicated that the carrying
amount of PSNC Energy's acquisition adjustment (goodwill) exceeded its fair
value, and as a result, PSNC Energy recorded an impairment charge of $230
million as the cumulative effect of an accounting change, effective January 1,
2002. SFAS 142 requires PSNC Energy to perform a valuation analysis annually.
Such an analysis will incorporate updated assumptions similar to those used for
the initial valuation.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by PSNC Energy described below are held
for purposes other than trading.
Interest rate risk - The tables below provide information about
long-term debt issued by PSNC Energy and other financial instruments that are
sensitive to changes in interest rates. For debt obligations, the tables present
principal cash flows and related weighted average interest rates by expected
maturity dates. For interest rate swaps, the figures shown reflect notional
amounts and related maturities. Fair values for debt and swaps represent quoted
market prices.
December 31, 2002 Expected Maturity Date
Millions of dollars
Liabilities 2003 2004 2005 2006 2007 Thereafter Total Fair Value
------------------------------------ ------- ---------- ---------- ---------- ---------- ----------- ---------- ------------
Long-Term Debt:
Fixed Rate ($) 7.5 7.5 3.2 3.2 3.2 266.0 290.6 325.4
Average Fixed Interest Rate (%) 9.47 9.47 8.75 8.75 8.75 7.0 7.2
Interest Rate Swaps:
Pay Variable/Receive Fixed ($) 7.5 7.5 3.2 3.2 3.2 16.0 40.6 2.9
Average Pay Interest Rate (%) 5.2 5.2 4.59 4.59 4.59 4.59 5.2
Average Receive Interest Rate (%) 9.0 9.0 8.75 8.75 8.75 8.75 9.0
December 31, 2001 Expected Maturity Date
Millions of dollars
Liabilities 2002 2003 2004 2005 2006 Thereafter Total Fair Value
------------------------------------ ------- ---------- ---------- ---------- ---------- ----------- ---------- ------------
Long-Term Debt:
Fixed Rate ($) 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 Swaps:
Pay Variable/Receive Fixed ($) 4.3 7.5 7.5 3.2 3.2 19.2 44.9 (0.1)
Average Pay Interest Rate (%) 7.82 6.00 6.00 5.26 5.26 5.26 6.00
Average Receive Interest Rate (%) 10.0 9.10 9.10 8.75 8.75 8.75 9.10
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.
Beginning in January 2003, PSNC Energy initiated a hedging program for
gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs
include a PGA clause that provides for the recovery of actual gas costs
incurred. PSNC Energy will include in its PGA the results of its hedging
program, and will seek approval of this accounting treatment from the NCUC
during the annual prudence review in 2003. The offset to the change in fair
value of these derivatives will be recorded as a regulatory asset or liability.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Reports......................................... 136
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001........... 137
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000............................. 138
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000.............................. 139
Consolidated Statements of Capitalization as of
December 31, 2002 and 2001....................................... 140
Consolidated Statements of Comprehensive Income (Loss) and
Changes in Common Equity for the Years Ended December
31, 2002, 2001 and 2000........................................ 140
Notes to Consolidated Financial Statements......................... 141
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, 2002 and 2001, and the related Consolidated
Statements of Operations, Comprehensive Income (Loss) and Changes in Common
Equity and of Cash Flows for each of the three years in the period ended
December 31, 2002. Our audits also included the financial statement schedule
listed in Part IV at Item 15. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with 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, 2002
and 2001, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2002 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 1 and 2 to the consolidated financial statements, the
Company adopted Statement of Financial Standards No. 142, "Goodwill and Other
Intangibles," effective January 1, 2002 and changed its method of accounting for
operating revenues associated with its regulated utility operations effective
January 1, 2000.
s/Deloitte & Touche LLP
Columbia, South Carolina
February 7, 2003
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS
- -------------------------------------------------------------------------------------------- --------------------------
December 31, (Millions of dollars) 2002 2001
- -------------------------------------------------------------------------------------------- --------------------------
Assets
Gas Utility Plant $895 $855
Accumulated depreciation (318) (288)
Acquisition adjustment, net of accumulated amortization (Note 3) 210 439
- -------------------------------------------------------------------------------------------- --------------------------
Gas Utility Plant, Net 787 1,006
- -------------------------------------------------------------------------------------------- --------------------------
Nonutility Property and Investments, Net 28 29
- -------------------------------------------------------------------------------------------- --------------------------
Current Assets:
Cash and temporary investments 1 18
Restricted cash and temporary investments 7 2
Receivables, net of allowance for uncollectible accounts
of $2 and $1 98 70
Receivables - affiliated companies 14 12
Inventories (at average cost):
Stored gas 38 47
Materials and supplies 6 8
Prepayments 1 -
Deferred income taxes, net 3 -
- -------------------------------------------------------------------------------------------- --------------------------
Total Current Assets 168 157
- -------------------------------------------------------------------------------------------- --------------------------
Deferred Debits:
Due from affiliate-pension asset (Note 6) 14 14
Regulatory assets 20 11
Other 7 4
- ------------------------------------------------------------------------ --------------------------
--------------------
Total Deferred Charges and Other Assets 41 29
- ------------------------------------------------------------------------ --------------------------
--------------------
Total $1,024 $1,221
============================================================================================ ==========================
======================================================================== ==========================
Capitalization and Liabilities
Capitalization:
Common equity $487 $715
Long-term debt, net (Notes 7 & 10) 286 290
--------------------
- -------------------------------------------------------------------------------------------- --------------------------
Total Capitalization 773 1,005
- -------------------------------------------------------------------------------------------- --------------------------
--------------------
Current Liabilities:
Short-term borrowings (Notes 8 & 10) 31 -
Current portion of long-term debt (Note 7) 8 4
Accounts payable 44 41
Accounts payable - affiliated companies 7 10
Taxes accrued 5 5
Customer prepayments and deposits 12 17
Distributions/Dividends declared and interest accrued 11 6
Other 9 3
- -------------------------------------------------------------------------------------------- --------------------------
--------------------
Total Current Liabilities 127 86
- -------------------------------------------------------------------------------------------- --------------------------
--------------------
Deferred Credits:
Deferred income taxes, net (Note 9) 91 86
Deferred investment tax credits (Note 9) 2 2
Due to affiliate-postretirement benefits (Note 6) 16 14
Regulatory liabilities 1 14
Other 14 14
- -------------------------------------------------------------------------------------------- --------------------------
Total Deferred Credits and Other Liabilities 124 130
- -------------------------------------------------------------------------------------------- --------------------------
Commitments and Contingencies (Note 11) - -
- -------------------------------------------------------------------------------------------- --------------------------
Total $1,024 $1,221
============================================================================================ ==========================
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
- ------------------------------------------------------------------------ --------------- --------------- -------------
For the Years Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Millions of dollars
Operating Revenues (Note 2) $356 $453 $547
Cost of Gas 190 286 375
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Gross Margin 166 167 172
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Operating Expenses:
Operation and maintenance 70 69 67
Depreciation and amortization 35 43 42
Other taxes 7 6 6
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Total Operating Expenses 112 118 115
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Operating Income 54 49 57
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Other Income, including allowance for equity funds
used during construction of $1, $0 and $0 3 6 8
Interest Charges, net of allowance for borrowed funds
used during construction of $0, $1 and $1 21 22 20
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Income Before Income Taxes and
Cumulative Effect of Accounting Change 36 33 45
Income Taxes (Note 9) 13 18 24
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Income Before Cumulative Effect of Accounting Change 23 15 21
Cumulative Effect of Accounting Change, net of taxes (Note 2) (230) - 7
- ------------------------------------------------------------------------ --------------- --------------- -------------
- ------------------------------------------------------------------------ --------------- --------------- -------------
Net Income (Loss) $(207) $15 $28
======================================================================== =============== =============== =============
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
For the Years Ended December 31, 2002 2001 2000
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Millions of dollars
Cash Flows From Operating Activities:
Net income (loss) $(207) $15 $28
Adjustments to reconcile net income to net cash provided
from operating activities:
Cumulative effect of accounting change, net of taxes 230 - (7)
Depreciation and amortization 37 46 45
Allowance for funds used during construction (1) (1) (1)
Excess distributions (undistributed earnings
of equity method investee) - 3 (3)
Gain on sale of assets - - (1)
Over (under) collection, fuel adjustment clause (24) 23 7
Change in certain assets and liabilities:
(Increase) decrease in receivables, net (30) 58 (68)
(Increase) decrease in inventories 11 (15) (3)
(Increase) decrease in regulatory assets 1 1 (5)
(Increase) decrease in regulatory liabilities 1 - -
Increase (decrease) in accounts payable and advances 1 (68) 78
Increase (decrease) in deferred income taxes, net 2 3 3
Changes in other assets (6) 6 (4)
Changes in other liabilities 3 8 4
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Net Cash Provided From Operating Activities 18 79 73
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Cash Flows From Investing Activities:
Construction expenditures, net of AFC (47) (74) (38)
Increase in investments - - (1)
Proceeds on sale of assets - 1 8
Nonutility and other (1) - -
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Net Cash Used For Investing Activities (48) (73) (31)
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Cash Flows From Financing Activities:
Proceeds from issuance of medium-term notes - 148 -
Capital contributions from parent - 3 -
Retirement of long-term debt and common stock (4) (4) (9)
Distributions/Dividend payments (14) (18) (21)
Short-term borrowings, net 31 (125) (13)
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Net Cash Provided From (Used For) Financing Activities 13 4 (43)
================================================================= ================= ================ ==================
================================================================= ================= ================ ==================
Net Increase (Decrease) in Cash and Temporary Investments (17) 10 (1)
Cash and Temporary Investments, January 1 18 8 9
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
- ----------------------------------------------------------------- ----------------- ---------------- ------------------
Cash and Temporary Investments, December 31 $1 $18 $8
================================================================= ================= ================ ==================
================================================================= ================= ================ ==================
Supplemental Cash Flow Information:
Cash paid for:
Interest (net of capitalized interest of $1, $1 and $1) $19 $16 $21
Income taxes 14 12 25
In connection with the acquisition of Public Service Company of North Carolina,
Inc. by SCANA Corporation in 2000, $21 million in common stock was cancelled.
The application of push-down accounting for the acquisition resulted in a $466
million acquisition adjustment. The implementation of SFAS 142 resulted in a
$230 million transitional non-cash write-down of the acquisition adjustment in
2002. (See Note 2.)
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) 2002 2001
- ------------------------------------------------------------------------------------ -------------- ---------------
Common Equity:
Common stock, $1 par, 1,000 shares authorized and issued in 2002 and 2001 - -
Capital in excess of par value $686 $706
Accumulated other comprehensive loss (1) -
Retained earnings (deficit) (198) 9
--------------
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Common Equity 487 715
- ------------------------------------------------------------------------------------ -------------- ---------------
--------------
Long-term Debt:
Senior debentures (unsecured):
10% due 2004 (1) 9 12
8.75% due 2012 (1) 32 32
6.99% due 2026 50 50
7.45% due 2026 50 50
Medium-term notes:
6.625% due 2011 150 150
Less - Current maturities (8) (4)
- ------------------------------------------------------------------------------------ -------------- ---------------
- ------------------------------------------------------------------------------------ -------------- ---------------
283 290
Fair market value of interest rate swaps 3 -
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Long-Term Debt, Net 286 290
- ------------------------------------------------------------------------------------ -------------- ---------------
- ------------------------------------------------------------------------------------ -------------- ---------------
Total Capitalization $773 $1,005
==================================================================================== ============== ===============
(1) Fixed rate debt hedged by variable interest rate swap
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
AND CHANGES IN COMMON EQUITY
Accumulated
Capital Other Retained Total
Millions of dollars Common Stock in Excess Comprehensive Earnings Common
Shares Amount of Par Loss (Deficit) Equity
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
Balance at December 31, 1999 20,577,967 $21 $139 $72 $232
Cancellation of Shares Due to (20,576,967) (21) 564 (72) 471
Acquisition
Net Income 28 28
Cash Dividends Declared (19) (19)
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
Balance at December 31, 2000 - 703 9 712
1,000
Capital Contributions From Parent 3 3
Net Income 15 15
Cash Dividends Declared (15) (15)
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
Balance at December 31, 2001 - 706 - 9 715
1,000
Net Loss (207) (207)
Unrealized Losses on Hedging Activities,
net of taxes ($0.5) $(1) (1)
------ ---
Comprehensive Loss (208)
Cash Distributions/Dividends Declared (20) (20)
- ------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
- ------------------------------------------- ------------- ----------- ------------- ----------------- -----------
Balance at December 31, 2002 1,000 $- $686 $(1) $(198) $487
=========================================== ============= =========== ============= ================= =========== ==============
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 2000, the accounts of PSNC Production Corporation and SCANA
Public Service Company LLC are also 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, "Accounting for the Effects of Certain Types of
Regulation". SFAS 71 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, 2002, approximately $19.7 million and $1.1 million
of regulatory assets and liabilities, respectively, as shown below.
December 31,
Millions of dollars 2002 2001
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Accumulated deferred income taxes $(0.7) $(0.4)
Under- (over-) collections - Gas Cost Adjustment Clause 10.6 (13.8)
Deferred environmental remediation costs 9.0 10.2
Other regulatory assets (liabilities), net (0.3) 0.4
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Total $18.6 $(3.6)
================================================================================
Accumulated deferred income taxes represent deferred income tax
liabilities applicable to utility operations that have not been reflected in
customer rates for which future recovery is probable, offset by deferred income
tax assets, which will be reflected in customer rates as a result of reduced
revenue requirements due to the amortization of deferred investment tax credits.
Under- (Over-) collections - gas cost adjustment represents amounts
under- or over- collected from customers pursuant to the Company's Rider D
mechanism approved by the North Carolina Utilities Commission (NCUC). (See Note
1F.)
Deferred environmental remediation costs represent the costs associated
with the assessment and cleanup of environmental sites at manufactured gas plant
(MGP) sites currently or formerly owned by the Company. Management believes that
all MGP cleanup costs will be recoverable through gas rates. (See Note 11.)
The NCUC has reviewed and approved through specific orders most of the
items shown as regulatory assets. Other items represent costs which are not yet
approved for recovery by the NCUC. 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 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 are maintained in accordance with
the Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and as adopted by the NCUC.
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.
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 12.1%, 7.0%
and 6.8% for the years ended December 31, 2002, 2001 and 2000, respectively.
These rates do not exceed the maximum allowable rate as calculated under FERC
Order No. 561.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services
are provided to customers, and include estimated amounts for natural gas
delivered and facilities charges not yet billed. Unbilled revenues totaled
approximately $27.7 million and $20.2 million as of December 31, 2002 and 2001,
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 undercollected from customers
approximately $10.6 million at December 31, 2002 and overcollected from
customers approximately $13.8 million at December 31, 2001.
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.
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 4.3% for the year ended December 31, 2002 and 4.1% for
the years ended December 31, 2001 and 2000.
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets,"
effective January 1, 2002. The Company considers the amounts categorized by the
FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and
ceased amortization of such amounts upon the adoption of SFAS 142. These amounts
are related to acquisition adjustments of approximately $466 million recorded on
the books of the Company. The Company has no other significant intangible assets
subject to amortization as provided in SFAS 142.
The Company considers the amounts categorized by FERC as "acquisition
adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of
such amounts upon the adoption of SFAS 142. These amounts are related to the
acquisition adjustment of approximately $466 million recorded on the books of
the Company. The Company has no other intangible assets subject to amortization
as provided in SFAS 142.
If the Company had ceased amortization of the acquisition adjustment
during all periods presented in the condensed consolidated statements of
operations, net income (loss) would have been as follows:
(Millions of dollars) 2002 2001 2000
---- ---- ----
Net Income (Loss) as Reported $(207) $14.8 $27.8
Amortization of Acquisition Adjustment - 13.3 13.4
----- - - ---- - ----
Net Income (Loss) as Adjusted $(207) 28.1 41.2
====== == ==== == ====
In connection with the implementation of SFAS 142, the Company
performed a valuation analysis of its acquisition adjustment using an
independent appraisal. The analysis indicated that the carrying amount of the
acquisition adjustment exceeded its fair value by $230 million. As a result, the
Company recorded an impairment charge of $230 million in the fourth quarter of
2002. The charge is reflected on the statements of operations as the cumulative
effect of an accounting change.
H. Income Taxes
The Company is included in the consolidated federal income tax return
of SCANA Corporation for 2002 and 2001. 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 Energy, in the form
of capital contributions. In 2002 and 2001 capital contributions of $0.6 million
and $3.1 million, respectively, were received by PSNC Energy under such
provisions.
I. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt
and are amortized as components of "Interest on long-term debt, net" over the
terms of the respective debt issues. Other issuance expense and gains or losses
on reacquired debt that is refinanced are recorded in other deferred debits or
credits and amortized over the term of the replacement debt. The Company
amortized 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.
J. 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 clean up each site.
These estimates are refined as additional information becomes available;
therefore, actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site assessments and
cleanup relate solely to regulated operations. Such amounts are recorded in
deferred debits and amortized with recovery provided through rates.
K. Cash and 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.
L. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142,
"Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141
requires all acquisitions to be accounted for utilizing the purchase method.
SFAS 142 addresses how goodwill and other intangible assets should be accounted
for after they have been recorded in the financial statements (see Note 1G).
In June 2001, FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations," which becomes effective for financial statements issued for fiscal
years beginning after June 15, 2002. Accordingly, the Company adopted this
standard effective January 1, 2003. SFAS No. 143 applies to legal obligations
associated with the retirement of tangible long-lived assets (ARO) and requires
the Company to recognize, as a liability, the fair value of an ARO in the period
in which it is incurred and to accrete the liability to its present value in
future periods. The Company believes that any ARO related to the Company's
property would be insignificant and, due to the indeterminate life of the
related assets, an ARO could not be reasonably estimated.
The Company records cost of removal as a component of accumulated
depreciation for property that does not have an associated legal retirement
obligation. As of December 31, 2002, the Company estimates that approximately
$70 million of its accumulated depreciation balance is related to this
regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," became 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.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The
provisions of SFAS 145, among other things, discontinue treatment of gains or
losses from the early extinguishment of debt as extraordinary items unless such
early extinguishment meets the criteria of Accounting Principles Board Opinion
No. 30. The Company will adopt SFAS 145 effective January 1, 2003 and does not
expect that such initial adoption will have any impact on the Company's results
of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in July 2002. This statement requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The Company will adopt SFAS 146 effective January 1, 2003, and does not expect
that such initial adoption will have any impact on the Company's results of
operations, cash flows or financial position.
M. Related Party Transactions
The Company has related party transactions with two of its subsidiaries
and their investees. The Company records as cost of gas the storage costs
charged by Pine Needle. These gas costs were $5.1 million, $5.3 million and $5.3
million in 2002, 2001 and 2000, respectively. The Company owed Pine Needle $0.4
million, $0.4 million and $0.5 million at December 2002, 2001 and 2000,
respectively. The Company also records as gas costs transportation charges to
Cardinal. These gas costs were $11.9 million, in 2002, 2001 and 2000,
respectively. The Company owed Cardinal $1.0 million at December 31, 2002, 2001
and 2000, respectively.
N. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2002.
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. ACCOUNTING CHANGES
As a result of the January 1, 2002 adoption of SFAS 142, the Company
recorded a $230 million impairment charge related to its acquisition adjustment
(see Note 3). This charge is reflected on the Consolidated Statements of
Operations as the cumulative effect of an accounting change. See additional
information at Note 1G.
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.
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 recorded a utility plant acquisition adjustment of
approximately $466 million, which reflected 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 was being amortized over 35 years on the
straight-line basis. See Note 1G.
4. SALE OF SUBSIDIARIES
Effective January 1, 2001 PSNC Production Corporation and SCANA Public
Service Company LLC 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
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. The Company revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the deferred cost of gas 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 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001
$.215 February-June 2002 $.750 February-March 2001
$.350 July-October 2002 $.650 April-August 2001
$.410 November-December 2002 $.500 September-October 2001
$.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase
the benchmark cost of gas from $.410 to $.460 per therm effective for service
rendered on and after January 1, 2003.
In April 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.
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. In June 2000 the NCUC approved the
Company's requests for disbursement of up to $28.4 million from the Company's
expansion fund to extend natural gas service to Madison, Jackson and Swain
Counties in western North Carolina. The Company estimates that the cost of this
project will be approximately $31.4 million. The Madison County and Jackson
County portions of the project were completed by the end of 2002. Through
December 31, 2002 approximately $16.9 million had been spent on this project.
The unused portion of the Company's expansion fund is recorded in prepaid
assets.
In December 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.
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 employees of the Company
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.
For the years ended December 31, 2002 and 2001, the Company's net
periodic benefit income was approximately $0.2 million and $1.2 million,
respectively, for the pension plan and net periodic benefit cost was
approximately $1.1 million and $2.0 million, respectively, for the
postretirement plan. 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.
Disclosures required for these plans under SFAS 132, "Employer's
Disclosures about Pensions and Other Postretirement Benefits," for the six
months ended June 30, 2000, which is the relevant period prior to the Plan
mergers, are set forth in the following table:
Millions of Dollars Retirement Benefits Other Postretirement Benefits
--------------------------------------------------------------
Components of Net Periodic Benefit Cost
Service Cost $0.8 $ 0.1
Interest Cost 1.6 0.4
Expected return on plan assets (2.2) n/a
----- --- ---
Net periodic benefit cost $0.2 $ 0.5
==== =====
Assumptions
Discount rate 8.00 % 8.00 %
Expected return on plan assets 9.50 % n/a
Rate of compensation increase Age-related Age-related
Changes in Benefit Obligations
Benefit Obligation, beginning
of period $38.7 $ 8.9
Service Cost 0.8 0.1
Interest Cost 1.6 0.4
Benefits paid (2.5) (0.3)
Actuarial loss 1.3 2.1
--- --- ---- ---
Benefit Obligation at end of $39.9 $ 11.2
===== ======
period
Change in Plan Assets
Fair value of plan assets,
beginning of period
of period $47.9 n/a
Actual return on plan assets 0.8 n/a
Benefits paid (2.5) n/a
- ----
Fair value of plan assets at end
of period
of period $46.2 n/a
=====
Funded Status of Plans
Funded status, beginning of period $6.3 $(11.2)
Unrecognized actuarial loss 2.7 2.1
-- --- --- ---
Net asset (liability) recognized $9.0 $(9.1)
==== ======
Health Care Trends
The determination of net periodic other postretirement health care
benefit cost for the six months ended June 30, 2000 was based on the following
assumptions.
Health care cost trend rate 8.00%
Ultimate health care cost trend rate 5.50%
Year achieved 2005
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. No
options were granted subsequent to September 30, 1999.
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's common stock could have been
granted to officers and key employees of the Company at 90% 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.
As of December 31, 1999 options outstanding under the plans totaled
644,145 with a weighted average exercise price of $19.08 and a weighted average
remaining contractual life of 2.6 years. Exercise prices for these options
ranged from $12.86 to $21.25. All of these options were exercised in 2000.
7. LONG-TERM DEBT
The annual amounts of long-term debt maturities for the years 2003
through 2007 are summarized as follows:
- ---------------- ----------------- ------------------ -----------------
Year Amount Year Amount
- ---------------- ----------------- ------------------ -----------------
(Millions of Dollars)
2003 $7.5 2006 $3.2
2004 7.5 2007 3.2
2005 3.2
- ---------------- ----------------- ------------------ -----------------
8. SHORT-TERM BORROWINGS
Millions of dollars 2002 2001
- ------------------------------------------------------------- ---------------
Lines of credit $125.0 $125.0
Unused lines of credit $125.0 $125.0
Short-term borrowings outstanding:
Commercial paper (270 or fewer days) $31.1 -
Weighted average interest rate 1.42% n/a
The Company pays fees to banks as compensation for committed lines of
credit.
The Company's commercial paper outstanding totaled $31.1 million at
December 31, 2002, at a weighted average interest rate of 1.42%. The Company had
no commercial paper outstanding at December 31, 2001.
9. INCOME TAXES
Total income tax expense attributable to income (before cumulative
effects of accounting changes) for 2002, 2001 and 2000 is as follows:
Millions of dollars 2002 2001 2000
- ---------------------------------------------------- ----------------- ---------------- ----------------
Current taxes:
Federal $9.7 $14.0 $18.6
State 2.0 3.0 3.9
- ---------------------------------------------------- ----------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ----------------
Total current taxes 11.7 17.0 22.5
- ---------------------------------------------------- ----------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ----------------
Deferred taxes, net:
Federal 1.7 1.2 1.5
State 0.3 0.3 0.3
- ---------------------------------------------------- ----------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ----------------
Total deferred taxes 2.0 1.5 1.8
- ---------------------------------------------------- ----------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ----------------
Investment tax credits:
Amortization of amounts deferred - Federal (0.3) (0.3) (0.4)
- ---------------------------------------------------- ----------------- ---------------- ----------------
- ---------------------------------------------------- ----------------- ---------------- ----------------
Total investment tax credits (0.3) (0.3) (0.4)
- ---------------------------------------------------- ----------------- ---------------- ----------------
Total income tax expense $13.4 $18.2 $23.9
==================================================== ================= ================ ================
The difference between actual income tax expense and the amount
calculated from the application of the statutory 35% federal income tax rate to
pre-tax income (before cumulative effects of accounting changes) is reconciled
as follows:
Millions of dollars 2002 2001 2000
- -----------------------------------------------------------------------------------------------------------
Income before cumulative effect of accounting change $22.6 $14.8 $21.2
Total income tax expense:
Charged to operating expense 12.1 15.7 20.6
Charged to other income 1.3 2.5 3.3
- -----------------------------------------------------------------------------------------------------------
Total pre-tax income $36.0 $33.0 $45.1
===========================================================================================================
===========================================================================================================
Income taxes on above at statutory federal income tax rate $12.6 $11.6 $15.8
Increases (decreases) attributed to:
State income taxes (less federal income tax effect) 1.6 2.1 2.8
Non-deductible book amortization of acquisition adjustments - 4.7 4.7
Amortization of federal investment tax credits (0.3) (0.3) (0.4)
Other differences, net (0.5) 0.1 1.0
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
Total income tax expense $13.4 $18.2 $23.9
===========================================================================================================
The tax effects of significant temporary differences comprising the Company's
net deferred tax liability of $87.7 million at December 31, 2002 and $85.8
million at December 31, 2001 (see Note 1H) are as follows:
- ---------------------------------------------------------------------------------- ---------------- ------------------
Million of dollars 2002 2001
- ---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax assets:
Unamortized investment tax credits - -
Other $5.1 $1.5
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax assets 5.1 1.5
- ---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 88.1 85.2
Other 4.7 2.1
- ---------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax liabilities 92.8 87.3
- ---------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability $87.7 $85.8
================================================================================== ================ ==================
10. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2002 and 2001 are as follows:
Millions of dollars 2002 2001
--------------------------------------------- ----------------------------- ------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
--------------------------------------------- -------------- -------------- --------------- --------------
Assets:
Cash and temporary cash investments $1.0 $1.0 $18.0 $18.0
Liabilities:
Short-term borrowings 31.1 31.1 - -
Long-term debt 291.0 328.3 295.0 298.0
--------------------------------------------- -------------- -------------- --------------- --------------
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. Early 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 (loss), depending upon the intended use of the derivative
and the resulting designation. The impact on the Company of adopting SFAS 133
was not material.
The Company has two outstanding interest rate swap
agreements to pay variable and receive fixed rate interest payments on a
combined notional amount of $40.6 million at December 31, 2002. These swaps were
designated as fair value hedges of the Company's $8.6 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. Receipts or payments related to the
interest rate swaps are credited or charged to interest expense as incurred.
11. COMMITMENTS AND CONTINGENCIES
A. Environmental
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's actual remediation costs for these sites will depend on a number of
factors, such as actual site conditions, third-party claims and recoveries from
other potentially responsible parties (PRPs). In September 2002 an allocation
agreement was reached relieving the Company of liability for two of the seven
sites. The Company has recorded a liability and associated regulatory asset of
$7.8 million, which reflects its estimated remaining liability at December 31,
2002. Amounts incurred to date that have not been recovered through gas rates
are approximately $1.2 million. Management believes that all MGP cleanup costs
will be recoverable through gas rates.
B. Claims and Litigation
The Company is also engaged in various claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
C. Purchase Commitments
As of December 21, 2002 purchase commitments under forward contracts
for natural gas purchases are $175 million and $56 million for 2003 and 2004,
respectively.
12. SEGMENT OF BUSINESS INFORMATION
For the years ended December 31, 2002 and 2001, Gas Distribution was
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). Gas distribution uses operating income to measure profitability.
The Company did not have deferred tax assets prior to 2002, and has not had
intersegment revenue subsequent to 2000.
Disclosure of Reportable Segments
Millions of dollars
- --------------------------------------- -------------------- -------------- --------------------- ---------------
Gas All Adjustments/ Consolidated
2002 Distribution Other Eliminations Total
- --------------------------------------- -------------------- -------------- --------------------- ---------------
External Revenue $356 - - $356
Depreciation & Amortization 35 - - 35
Operating Income 54 n/a - 54
Interest Expense 21 - - 21
Segment Assets 1,007 $28 (11) 1,024
Expenditures for Assets 48 - - 48
Deferred Tax Assets 3 - - 3
- --------------------------------------- -------------------- -------------- --------------------- ---------------
Millions of dollars
- --------------------------------------- -------------------- -------------- --------------------- ---------------
Gas All Adjustments/ Consolidated
2001 Distribution Other Eliminations Total
- --------------------------------------- -------------------- -------------- --------------------- ---------------
External Revenue $453 - -
$453
Depreciation & Amortization 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
- --------------------------------------- -------------------- -------------- --------------------- ---------------
Million of dollars
- ------------------------------------- --------------- ------------ ---------- ------------------ ----------------
Gas Energy All Adjustments/ Consolidated
2000 Distribution Marketing Other Eliminations Total
- ------------------------------------- --------------- ------------ ---------- ------------------ ----------------
External Revenue $432 $141 - $(26)
$547
Intersegment Revenue - 1 $30 (31)
-
Depreciation & Amortization 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
- ------------------------------------- --------------- ------------ ---------- ------------------ ----------------
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of dollars
- ---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------
First Second Third Fourth
2002 Quarter Quarter Quarter Quarter Annual
- ---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------
Total operating revenues $134 $49 $39 $134 $356
Operating income (loss) 38 1 (6) 21 54
Income before cumulative effect of accounting change 21 (2) (6) 10 23
Cumulative effect of accounting change (1) (230) - - - (230)
Net income (loss) (209) (2) (6) 10 (207)
Millions of dollars
- --------------------------------------------------------- ------------ ----------- ----------- ----------- -----------
First Second Third Fourth
2001 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
- --------------------------------------------------------- ------------ ----------- ----------- ----------- -----------
(1) The cumulative effect of accounting change is attributable to the
adoption of SFAS 142. The amount of the cumulative effect was finalized
in the fourth quarter 2002 and, as prescribed in the standard, was
recorded effective January 1, 2002. See Note 1G.
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 Energy: 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 I Directors," "Continuing Directors," and "Other Information - Section
16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy
statement for the 2003 annual meeting of shareholders which was filed with the
SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of
1934.
SCE&G: DIRECTORS
The directors listed below were elected May 2, 2002 (except as otherwise
indicated) to hold office until the next annual meeting of SCE&G's shareholders
on May 1, 2003.
Name and Year First Age Principal Occupation; Directorships
Became Director
Bill L. Amick 59 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 Energy, Gastonia, NC; Blue Cross
and Blue Shield of South Carolina,
Columbia, SC.
James A. Bennett 42 Since August 2002, Executive Vice President and Director of Public Affairs, First Citizens
(1997) Bank,
Columbia, SC.
From May 2000 to July 2002, President and
Chief Executive Officer of South
Carolina Community Bank, 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 Energy, Gastonia, NC.
William B. Bookhart, Jr. 61 For more than five years, a partner in Bookhart Farms, Elloree, SC (general farming).
(1979)
Director, SCANA Corporation, Columbia, SC; PSNC Energy, Gastonia, NC.
William C. Burkhardt 65 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 Energy, Gastonia, NC; Capital Bank
and Industrial Microwave Systems,
Raleigh, NC.
Elaine T. Freeman 67 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 Energy, 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
D. Maybank Hagood 41 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 Energy, Gastonia, NC.
W. Hayne Hipp 63 For more than five years, Chairman and Chief Executive Officer of The Liberty
(1983) Corporation, Greenville, SC (broadcasting holding company).
Director, SCANA Corporation, Columbia,
SC; PSNC Energy, Gastonia, NC; The
Liberty Corporation, Greenville, SC.
Lynne M. Miller 51 For more than five years, Chief Executive Officer of Environmental Strategies Corporation,
(1997) Reston, VA (environmental consulting and engineering firm).
Director, SCANA Corporation, Columbia,
SC; PSNC Energy, Gastonia, NC; Adams
National Bank-(a subsidiary of Abigail
Adams National Bancorp, Inc.),
Washington, DC.
Maceo K. Sloan 53 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. (NCM) (investment management company), Durham, NC. Since
January 2003, Chief Investment Officer of NCM.
Director, SCANA Corporation, Columbia,
SC; PSNC Energy, Gastonia, NC; M&F
Bankcorp, Inc., Durham, NC; Trustee,
Teachers Insurance Annuity Association
- College Retirement Equity Fund
(TIAA-CREF).
Harold C. Stowe 56 For more than five years, President of Canal Holdings, LLC and its predecessor company,
(1999) Conway, SC (forest products industry).
Director, SCANA Corporation, Columbia,
SC; PSNC Energy, Gastonia, NC; Canal
Holdings, LLC, Conway, SC; Ruddick
Corporation, Charlotte, NC.
William B. Timmerman 56 For more than five years, Chairman of the Board,
President and Chief Executive Officer, (1991) SCANA Corporation,
Columbia, SC.
Director, SCANA Corporation, Columbia,
SC; PSNC Energy, Gastonia, NC;
ITC^DeltaCom, Inc., West Point, GA;
The Liberty Corporation, Greenville,
SC.
G. Smedes York 62 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 Energy, 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 56 Chairman of the Board and Chief Executive Officer *-present
H. T. Arthur 57 Senior Vice President, General Counsel and Assistant Secretary 1998-present
Vice President, General Counsel and Assistant Secretary *-1998
S. D. Burch 46 Senior Vice President, Natural Gas Procurement and Asset Management 2003-present
Deputy General Counsel and Assistant Secretary 2000-2003
Attorney - SCANA *-2000
S. A. Byrne 43 Senior Vice President-Nuclear Operations 2001-present
Vice President-Nuclear Operations 2000-2001
General Manager-Nuclear Plant Operations *-2000
D. C. Harris 50 Senior Vice President-Human Resources 2000-present
Vice President Human Resources, Austin Quality Foods, Inc., Cary, NC *-2000
N. O. Lorick 52 President and Chief Operating Officer 2000-present
Vice President - Fossil and Hydro Operations *-2000
K. B. Marsh 47 Senior Vice President and Chief Financial Officer 1998-present
Vice President - Finance and Chief Financial Officer *-1998
Controller *-2000
C. B. McFadden 58 Senior Vice President, Governmental Affairs and Economic Development 2003-present
Vice President, Governmental Affairs and Economic Development *-2003
*Indicates position held at least since March 1, 1998
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of SCE&G's common stock is held by its parent, SCANA Corporation. The
required forms indicate that no equity securities of SCE&G are owned by its
directors and officers. Based solely on a review of the copies of such forms and
amendments furnished to SCE&G and written representations from the officers and
directors, SCE&G believes that during 2002 all Section 16(a) filing requirements
applicable to its officers, directors and greater than 10% beneficial owners
were complied with, except that each of Jimmy E. Addison, H. Thomas Arthur,
Sarena D. Burch, Stephen A. Byrne, Mark R. Cannon, Duane C. Harris, Neville O.
Lorick, Charles B. McFadden and James E. Swan filed late his or her Form 3.
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 2003 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 2002 751,228(5) 760,949 16,435 219,200 536,884 44,614
Chairman, President and Chief 2001 660,238 17,611 129,781 60,884
- -
Executive Officer - SCANA 2000 524,261 354,486 17,888 35,620 50,230
-
N. O. Lorick 2002 376,538 317,808 16,958 77,816 145,487 22,132
President and Chief Operating 2001 385,252 18,701 36,711 30,611
- -
Officer - SCE&G 2000 167,778 124,921 7,313 2,332 12,728
-
K. B. Marsh 2002 375,384 317,808 10,183 77,816 209,432 22,063
Senior Vice President 2001 334,234 10,554 36,711 29,097
- -
and Chief Financial Officer - 2000 276,172 150,720 10,613 11,627 24,254
-
SCANA
H. T. Arthur 2002 297,115 191,340 15,830 42,992 146,345 17,367
Senior Vice President and 2001 270,963 16,119 19,142 23,487
- -
General Counsel 2000 234,812 120,480 16,119 8,796 19,718
-
S. A. Byrne 2002 285,385 191,339 9,000 42,992 146,345 16,663
Senior Vice President-Nuclear 2001 244,232 9,285 19,142 22,064
- -
Operations - SCE&G 2000 183,555 123,492 11,100 8,796 12,962
-
- ------------------------------------ ------ --------------- ----------- ------------------ -------------- ----------- --------------
(1) Payments under the Annual Incentive Plan.
(2) For 2002, other annual compensation consists of automobile allowance and
life insurance premiums on policies owned by named executive officers of $9,000
and $7,435 for Mr. Timmerman; $9,000 and $7,958 for Mr. Lorick; $9,000 and
$1,183 for Mr. Marsh; $9,000 and $6,830 for Mr. Arthur and $9,000 and $0 for Mr.
Byrne. (3) Payouts under Performance Share.
(4) All other compensation for all named executive officers consists solely of
matching contributions to defined contribution plans. (5) Reflects actual salary
paid in 2002. Base salary of $761,000 became effective on February 21, 2002.
Options Grants and Related Information
Options/SAR Grants in Last Fiscal Year
Potential
Realizable Value at
Assumed Annual
Rates of Stock Price
Appreciation
Individual Grants for Option Term
- ------------------------------------------------------------------------------------------- -----------------------------
(a) (b) (c) (d) (e) (f) (g)
Number of % of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise or
SARs Employees in Base Price Expiration
Name Granted (#) Fiscal Year ($/Sh) Date 5% ($) 10%($)
- ------------------------- -------------- ----------------- --------------- ---------------- -------------- --------------
W. B. Timmerman 219,200 19.63 27.52 02/21/12 3,793,734 9,614,067
N. O. Lorick 77,816 6.97 27.52 02/21/12 1,346,776 3,412,994
K. B. Marsh 77,816 6.97 27.52 02/21/12 1,346,776 3,412,994
H. T. Arthur 42,992 3.85 27.52 02/21/12 744,070 1,885,620
S. A. Byrne 42,992 3.85 27.52 02/21/12 744,070 1,885,620
All the above options vest 33 1/3% on each of the first, second and third
anniversaries of the date of the grant, February 21, 2002.
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 67,007/317,594 $281,501/$1,122,564
N. O. Lorick 13,792,103,067 51,440/357,835
K. B. Marsh 19,988,106,166 85,274/374,752
H. T. Arthur 12,245/58,685 54,414/208,693
S. A. Byrne 12,245/58,685 54,414/208,693
(1)Based on the closing price of $30.96 per share on December 31, 2002, the last
trading date of the fiscal year.
Defined Benefit Plans
SCANA sponsors 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. Participants 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% of compensation under
the Social Security Wage Base and 10% of compensation in excess of the Social
Security Wage Base.
In addition to its Retirement Plan for all employees, SCANA sponsors
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% per year), to the executive officers named in the Summary Compensation Table
are as follows: Mr. Timmerman - $474,672; Mr. Lorick - $305,292; Mr. Marsh -
$367,140; Mr. Arthur - $114,516 and Mr. Byrne - $289,992.
Termination, Severance and Change in Control Arrangements
SCANA maintains an Executive Benefit Plan Trust. The purpose of the
trust is to assist in retaining and attracting 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
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
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 owed 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% 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% of
the target award in effect as of the date of the Change in Control.
The benefits and their respective amounts under the Supplementary Key
Executive Severance Benefits Plan 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 3%, calculated until the end
of the month preceding the month in which the benefits are distributed.
Compensation Committee Interlocks and Insider Participation
During 2002, decisions on various elements of executive compensation
were made by the Human Resources 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 Human Resources Committee or the
Long-Term Equity Compensation Plan Committee.
The names of the persons who serve on the Human Resources and the
Long-Term Equity Compensation Plan Committee can be found at Item 12, Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Information.
Director Compensation
Board Fees
Officers 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% 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. During 2002, the only
director remaining in the Voluntary Deferral Plan was Mr. Bennett, whose account
was credited with interest of $2,567 for the year.
Under the new plan, a director may elect to defer the 60% of the annual
retainer fee required to be paid in 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% of the
annual retainer fee not required to be paid in stock and up to 100% 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 2002, Ms. Miller and Messrs. Amick, Bennett, Burkhardt, Hipp,
Sloan, Stowe and York elected to defer 100% 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% 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 Human Resources Committee. The designated institutions are reviewed on an
annual basis by the Chief Executive Officer to assure compliance with the intent
of the program.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER INFORMATION
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 Ownership of SCANA Common Stock" in SCANA's definitive proxy
statement for the 2003 annual meeting of shareholders.
SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table lists shares beneficially owned on February 28, 2003 by each
director and each person named in the Summary Compensation table on page 158.
SECURITY OWNERSHIP OF MANAGEMENT
Amount and Nature Amount and Nature
of Beneficial Ownership of of Beneficial Ownership of
Name SCANA Common Stock *(1) (2) (3) Name SCANA Common Stock *(1) (2) (3)
- ----- -----
(4) (5) (4) (5)
--------------------------------- ---------------------------------
B. L. Amick (6)(7) 11,048 W. H. Hipp 4,897
H. T. Arthur 51,343 N. O. Lorick 69,456
J. A. Bennett (7) 2,366 K. B. Marsh 79,126
W. B. Bookhart, Jr. 22,565 L. M. Miller (7) 3,480
(6)(7)
W. C. Burkhardt (6)(7) 12,143 M. K. Sloan (6)(7) 4,317
S. A. Byrne 41,814 H. C. Stowe (6)(7) 4,299
E. T. Freeman (7) 6,703 W. B. Timmerman 251,584
D. M. Hagood (6)(7) 850 G. S. York (7) 11,727
*Each of the above owns less than 1% of the shares outstanding.
All directors and executive officers as a group (19 persons) total 662,150
shares, including 434,229 shares subject to currently exercisable options and
options that will become exercisable within 60 days. Total percent of class
outstanding is less than one 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-6,335; and by all directors, nominees
and executive officers 6,815 in total.
(2) Includes shares purchased through February 28, 2003, 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, 2003, each of the following directors had
acquired under the plan the number of hypothetical shares following his or
her name: Messrs. Amick-5,044, Bennett-5,715, Burkhardt-5,939, Hagood-1,988,
Hipp-5,327, Sloan-5,218, Stowe-5,022, York-5,567 and Ms. Miller-5,718.
(4) Includes shares subject to currently exercisable options and options that
will become exercisable within 60 days in the following amounts: Mr.
Timmerman-195,208; Mr. Lorick-52,745; Mr. Marsh-62,040; Mr. Byrne-35,888;
Mr. Arthur-35,888.
(5) Hypothetical shares acquired under the SCANA Executive Deferred Compensation
Plan are not included in the above table. As of February 28, 2003, each of
the following officers had acquired under the plan the number of
hypothetical shares following his name: Mr. Timmerman-18,681; Mr.
Lorick-2,531; Mr. Marsh- 4,394; Mr. Byrne-1,484; Mr. Arthur- 2,806.
(6) Serves on the Human Resources Committee. (7) Serves on the Long-Term Equity
Compensation Plan Committee.
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 Party Transactions"
in SCANA's definitive proxy statement for the 2003 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 2003
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 2002, SCANA paid $63,911 (including the value of non-utility in-
kind services provided by SCANA and its subsidiaries) to subsidiaries of The
Liberty Corporation for advertising expenses. SCANA's management believes that
these services, the majority of which were arranged through the use of an
independent third-party advertising agency, were provided at competitive market
rates.
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.
ITEM 14. CONTROLS AND PROCEDURES
SCANA:
As of December 31, 2002, an evaluation was performed under the
supervision and with the participation of the Company's management, including
the CEO and CFO, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures. Based on that evaluation, the
Company's management, including the CEO and CFO, concluded that the Company's
disclosure controls and procedures were effective as of December 31, 2002. There
have been no significant changes in the Company's internal controls or in other
factors that could significantly affect internal controls subsequent to December
31, 2002.
SCE&G:
As of December 31, 2002, an evaluation was performed under the
supervision and with the participation of SCE&G's management, including the CEO
and CFO, of the effectiveness of the design and operation of SCE&G's disclosure
controls and procedures. Based on that evaluation, SCE&G's management, including
the CEO and CFO, concluded that SCE&G's disclosure controls and procedures were
effective as of December 31, 2002. There have been no significant changes in
SCE&G's internal controls or in other factors that could significantly affect
internal controls subsequent to December 31, 2002.
PSNC Energy:
As of December 31, 2002, an evaluation was performed under the
supervision and with the participation of PSNC Energy's management, including
the CEO and CFO, of the effectiveness of the design and operation of PSNC
Energy's disclosure controls and procedures. Based on that evaluation, PSNC
Energy's management, including the CEO and CFO, concluded that PSNC Energy's
disclosure controls and procedures were effective as of December 31, 2002. There
have been no significant changes in PSNC Energy's internal controls or in other
factors that could significantly affect internal controls subsequent to December
31, 2002.
ITEM 15. 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 Energy 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
Energy are listed under Item 8 herein.
The Financial Statement Schedules filed as part of this
report for SCANA, SCE&G and PSNC Energy begin on page 166.
(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)of Regulation S-K,
instruments defining the rights of holders of long-term debt
of less than 10% of the total consolidated assets of SCANA,
for itself and its subsidiaries, of SCE&G, for itself and
its subsidiaries, and of PSNC Energy, for itself and its
subsidiaries, have been omitted and SCANA, SCE&G and PSNC
Energy agree to furnish a copy of such instruments to the
Commission upon request.
(b) Reports on Form 8-K during the fourth quarter of 2002 for SCANA, SCE&G and
PSNC Energy:
SCANA Corporation:
Date of report: October 9, 2002
Item reported: Item 5
South Carolina Electric & Gas Company:
Date of report: October 25, 2002
Item reported: Item 5
Public Service Company of North Carolina Incorporated: None
SCANA:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2002, 2001 and 2000 .
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
2002 37,814,016 18,691,795 - 39,037,760 17,468,051
2001 31,235,446 11,206,098 - 4,627,528 37,814,016
2000 8,110,867 26,590,435 - 3,465,856 31,235,446
Reserve for investment impairment
2002 4,928,768 - 451,718 4,477,050
-
2001 4,928,768 - 4,928,768
- -
2000 4,133,768 1,000,000 - 205,000 4,928,768
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2002 5,851,288 5,591,506 - 4,375,328 7,067,466
2001 7,349,339 2,623,315 - 4,121,366 5,851,288
2000 7,419,159 4,239,206 - 4,309,026 7,349,339
Provision for Supplemental
Executive Retirement
Plan
2002 6,859,125 1,589,025 - 451,653 7,996,497
2001 6,355,795 503,330 - 6,859,125
-
2000 6,487,365 - - 131,570 6,355,795
Provision for decontamination and
decommissioning
2002 2,394,187 - - 427,961 1,966,226
2001 2,814,569 - - 420,382 2,394,187
2000 3,223,821 - - 409,252 2,814,569
Provision for nuclear refueling
outage costs
2002 5,888,889 6,722,222 - 8,833,333 3,777,778
2001 - 5,888,889 - 5,888,889
-
2000 3,336,814 6,737,332 - 10,074,146 -
SCE&G:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2002, 2001 and 2000 .
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
2002 820,000 3,119,886 - 3,245,886 694,000
2001 577,000 3,273,754 - 3,030,754 820,000
2000 537,000 2,381,626 - 2,341,626 577,000
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2002 3,421,054 4,546,078 - 3,600,313 4,366,819
2001 4,575,192 1,689,873 - 2,844,011 3,421,054
2000 3,972,816 3,581,317 - 2,978,941 4,575,192
Provision for decontamination and
decommissioning
2002 2,394,187 - - 427,961 1,966,226
2001 2,814,569 - - 420,382 2,394,187
2000 3,223,821 - - 409,252 2,814,569
Provision for nuclear refueling
outage costs
2002 5,888,889 6,722,222 - 8,833,333 3,777,778
2001 - 5,888,889 - 5,888,889
-
2000 3,336,814 6,737,332 - 10,074,146 -
PSNC Energy:
Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31,
2002, 2001 and 2000.
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
2002 1,444,719 2,167,720 - 2,100,201 1,512,238
2001 2,402,696 4,158,568 - 5,116,545(a) 1,444,719
2000 2,702,014 2,417,566 - 2,716,884 2,402,696
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2002 1,201,125 923,010 - 884,437 1,239,698
2001 1,626,258 723,628 - 1,148,761 1,201,125
2000 2,197,615 494,629 - 1,065,986 1,626,258
Provision for post-retirement &
post-employment
2002 - - - -
-
2001 398,000 - 398,000 -
-
2000 6,658,753 1,227,823 - 7,488,576 398,000
(a)Includes $309,645 uncollectible reserve balance for SCANA Public Service
Company LLC which was sold to SCANA Energy Marketing effective January 1, 2001.
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 21, 2003
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/ J. E. Swan
J. E. Swan, Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp
J. A. Bennett L. M. Miller
W. B. Bookhart, Jr. M. K. Sloan
W. C. Burkhardt H. C. Stowe
E. T. Freeman G. S. York
D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 21, 2003
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 21, 2003
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/ J. E. Swan
J. E. Swan, Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp
J. A. Bennett L. M. Miller
W. B. Bookhart, Jr. M. K. Sloan
W. C. Burkhardt H. C. Stowe
E. T. Freeman G. S. York
D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 21, 2003
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/Jerry W. Richardson
Jerry W. Richardson
President and Chief Operating Officer
DATE: March 21, 2003
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/ J. E. Swan
J. E. Swan, Controller (Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp
J. A. Bennett L. M. Miller
W. B. Bookhart, Jr. M. K. Sloan
W. C. Burkhardt H. C. Stowe
E. T. Freeman G. S. York
D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: March 21, 2003
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this annual report on Form 10-K of SCANA Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, President,
Chief Executive Officer and
Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this annual report on Form 10-K of SCANA Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
d) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial Officer
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this annual report on Form 10-K of South Carolina
Electric & Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
e) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive
Officer and Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this annual report on Form 10-K of South Carolina
Electric & Gas Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
f) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief
Financial Officer
CERTIFICATION
I, William B. Timmerman, certify that:
1. I have reviewed this annual report on Form 10-K of Public Service
Company of North Carolina, Incorporated;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
g) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/William B. Timmerman
William B. Timmerman
Chairman of the Board, Chief Executive
Officer and Director
CERTIFICATION
I, Kevin B. Marsh, certify that:
1. I have reviewed this annual report on Form 10-K of Public Service
Company of North Carolina, Incorporated;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to filing date of
this annual report (the "Evaluation Date"); and
h) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 21, 2003
s/Kevin B. Marsh
Kevin B. Marsh
Senior Vice President and Chief Financial
Officer
EXHIBIT INDEX
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy 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 3.05 to
Registration Statement No. 333-101449 and incorporated by reference herein)
3.08 X Articles of Amendment of SCE&G, dated March 13, 2002 (Filed as Exhibit 3.06 to
Registration Statement No. 333-101449 and incorporated by reference herein)
3.09 X Articles of Amendment of SCE&G dated May 9, 2002 (Filed as Exhibit 3.07 to
Registration Statement No. 333-101449 and incorporated by reference herein)
3.10 X Articles of Amendment of SCE&G dated June 4, 2002 (Filed as Exhibit 3.08 to
Registration Statement No. 333-101449 and incorporated by reference herein)
3.11 X Articles of Amendment of SCE&G dated August 12, 2002 (Filed as Exhibit 3.09 to
Registration Statement No. 333-101449 and incorporated by reference herein)
3.12 X Articles of Incorporation of PSNC Energy (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)
3.13 X Articles of Amendment of PSNC Energy (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)
3.14 X Articles of Correction of PSNC Energy dated February 11, 2000 (Filed as Exhibit
3.03 to Registration Statement No. 333-45206 and incorporated by reference
herein)
EXHIBIT INDEX
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy Description
3.15 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)
3.16 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)
3.17 X By-Laws of PSNC Energy (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)
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
EXHIBIT INDEX
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy Description
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
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
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 as 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)
EXHIBIT INDEX
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy Description
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 to
Registration Statement No. 333-49960 and incorporated by reference herein)
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 through Fourth Supplemental Indenture referred to Exhibit 4.14 dated as of the
dates indicated below and filed as exhibits to Registration Statements whose file
numbers are set forth below and are incorporated by reference herein
January 1, 1996 Exhibit 4.09 to Registration No. 333-45206
December 15, 1996 Exhibit 4.10 to Registration No. 333-45206
February 10, 2000 Exhibit 4.11 to Registration No. 333-45206
February 12, 2001 Exhibit 4.05 to Registration No. 333-68516
4.16 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 Deferred
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
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy 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 4.03 to Registration Statement No. 333-18973 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 Service Agreement between SCE&G and SCANA Services, Inc., effective April 1, 2002
(Filed as Exhibit 10.01 to Registration Statement No. 333-101449 and incorporated by
reference herein)
12.01 X X X Statement Re Computation of Ratios
21.01 X Subsidiaries of the Registrant (Incorporated by reference herein from Item I,
Business-Corporate Structure in this Form 10-K)
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)
24.01 X X X Power of Attorney (Filed herewith)
EXHIBIT INDEX
Applicable to Form 10-K of
Exhibit PSNC
No. SCANA SCE&G Energy Description
99.1 X Certification of Principal Executive Officer (Filed herewith)
99.2 X Certification of Principal Financial Officer (Filed herewith)
99.3 X Certification of Principal Executive Officer (Filed herewith)
99.4 X Certification of Principal Financial Officer (Filed herewith)
99.5 X Certification of Principal Executive Officer (Filed herewith)
99.6 X Certification of Principal Financial Officer (Filed herewith)
* Management Contract or Compensatory Plan or Arrangement