================================================================================
                                  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




================================================================================


<PAGE>


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____.
                          ------
   South Carolina Electric & Gas Company  Yes   X     No____.
                                              ------
   Public Service Company of North Carolina, Incorporated Yes   X     No____.
                                                              ------

         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).








<PAGE>



                                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


<PAGE>




      Certifications Required by Rule 13a-14.........................       172

      Exhibit Index..................................................       178

      Certifications Pursuant to 18 U.S.C. Section 1350..............       193

<PAGE>


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


<PAGE>

<TABLE>
<CAPTION>

                                     PART I

ITEM 1.  BUSINESS

     CORPORATE STRUCTURE

                                                             SCANA CORPORATION
                                A holding company owning the direct, wholly owned subsidiaries listed below

          <S>                                                         <C>
          SOUTH CAROLINA ELECTRIC &                                    SCANA COMMUNICATIONS, INC.
          --------------------------                                   --------------------------
          GAS COMPANY                                                  Provides fiber optics telecommunications and
          -----------
          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.
          -------------                                                ----------------------------
          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
          --------------------
          COMPANY, INC.                                                division, markets natural gas in Georgia's
          -------------
          Acquires, owns and provides financing                        retail natural gas market.
          for SCE&G's nuclear fuel, fossil fuel
          and sulfur dioxide emission allowances.                      SERVICECARE, INC.
                                                                       -----------------
                                                                       Provides energy-related products and
          PUBLIC SERVICE COMPANY OF                                    service contracts on home appliances
          -------------------------
          NORTH CAROLINA, INCORPORATED                                 and heating and air conditioning units.
          ----------------------------
          Purchases, sells and transports
          natural gas to retail customers and markets                  PRIMESOUTH, INC.
                                                                       ----------------
          natural gas.                                                 Provides management and maintenance services
                                                                       for power plants and an alternate fuel facility.
          SOUTH CAROLINA PIPELINE
          CORPORATION                                                  SCANA RESOURCES, INC.
          -----------                                                  ---------------------
          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.
                                                                       --------------------
          regasification of natural gas.                               Provides administrative, management and other
                                                                       services to the subsidiaries and business units
          SCG PIPELINE, INC.                                           within SCANA Corporation.
          ------------------
          Organized to engage in the transportation of natural gas in Georgia
          and South Carolina.


</TABLE>



     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.


<PAGE>


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.


<PAGE>



     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.



<PAGE>


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.



<PAGE>


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:
<TABLE>
<CAPTION>

                                               Dekatherms Sales (in thousands)
-------------------------------------------------------------------------------------------------------------------------------
                                     The Company                           SCE&G                         PSNC Energy
                                                     %                                   %                              %
CLASSIFICATION               2002        2001      Change        2002        2001      Change     2002      2001      Change
-------------------------- ---------- ---------- ----------- ------------- --------- ---------- --------- --------- -----------

<S>                           <C>        <C>        <C>            <C>       <C>         <C>      <C>       <C>        <C>
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
========================== ========== ========== =========== ============= ========= ========== ========= ========= ===========

</TABLE>
        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.



<PAGE>


         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.


<PAGE>


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.


<PAGE>


ELECTRIC PROPERTIES

     Information on electric generating facilities, all of which are owned by
SCE&G except as noted, is as follows:
<TABLE>
<CAPTION>

                                                                                                           Net Generating
                                  Present                                                  Year               Capacity
  Facility                   Fuel Capability             Location                       In-Service      (Summer Rating) (MW)
  --------                   ---------------             --------                       ----------      --------------------
  Steam
  -----
<S>                    <C>                                                               <C>  <C>                <C>
  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
</TABLE>

(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


<PAGE>
<TABLE>
<CAPTION>


                     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

<S>                 <C>                                                                                    <C>
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.

</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                     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)
<S>                     <C>          <C>         <C>         <C>          <C>         <C>         <C>          <C>
       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
   ----------------- ------------ ------------------ ------------------ ----------- ------------------ -----------------
</TABLE>

        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.


<TABLE>

<CAPTION>

   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
       ------         -----       -----       -----       -----    ----------     -----      ---------       -----

<S>                      <C>          <C>         <C>        <C>        <C>          <C>          <C>           <C>
   Moody's              A3           A1          A1       Baa1         A3          P-1           A2           P-1
   Standard  &         BBB+          A-          A-        BBB        BBB          A-1           A-           A-1
   Poors
   ---------------- ----------- ----------- ----------- ---------- ----------- ------------ ------------- -------------
</TABLE>





        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.


<PAGE>



       Equity securities issuable under the Company's compensation plans at
December 31, 2002 are summarized as follows:
<TABLE>
<CAPTION>

                                     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
<S>                                            <C>                        <C>                  <C>
   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

</TABLE>

(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.

<PAGE>

<TABLE>
<CAPTION>

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
<S>                                                                  <C>           <C>        <C>        <C>         <C>
  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
------------ ---------- --------- ---------- ----------

</TABLE>


     (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.



<PAGE>



                                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



<PAGE>


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.


<PAGE>


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.


<PAGE>



        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.



<PAGE>


        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.


<PAGE>



        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.



<PAGE>


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.


<PAGE>



        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



<PAGE>



        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.


<PAGE>



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.


<PAGE>


        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.


<PAGE>



        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.


<PAGE>



        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.


<PAGE>


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.


<PAGE>


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
  -----------------------------------------------------------------------------
  -----------------------------------------------------------------------------
 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).



<PAGE>


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.


<PAGE>



        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.


<PAGE>



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 .



<PAGE>


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.

<TABLE>
<CAPTION>


  December 31, 2002                                                    Expected Maturity Date
  Millions of dollars

  Liabilities                          2003      2004      2005      2006        2007     Thereafter    Total      Fair Value
  ----------------------------------- -------- --------- --------- ---------- ----------- ----------- ----------- --------------

    Long-Term Debt:
<S>            <C>                     <C>      <C>       <C>        <C>          <C>      <C>         <C>           <C>
    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
  (%)
</TABLE>

     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.


<PAGE>



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
--------------------------- ----------- ---- ----------------
<TABLE>
<CAPTION>

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:
<S>   <C>                      <C>        <C>        <C>             <C>            <C>           <C>
  Long($)                      2.63       119.3      76.0            3.26           3.0           2.6
  Short($)                     2.64          1.6       1.1               -             -             -

(a) weighted average

</TABLE>

     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.


<PAGE>



     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


<PAGE>


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







<PAGE>


      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
==============================================================================




<PAGE>

<TABLE>
<CAPTION>


   ------------------------------------------------------------------------- ------------------- ---------------------
   December 31,  (Millions of dollars)                                              2002                 2001
   ------------------------------------------------------------------------- ------------------- ---------------------
   Capitalization and Liabilities
   Shareholders' Investment:
<S>                         <C>                                                    <C>                  <C>
       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.



<PAGE>







  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.


</TABLE>

<PAGE>



<TABLE>
<CAPTION>


SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
For the Years Ended December 31, (Millions of dollars)                                           2002         2001          2000
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Operating Activities:
<S>                                                                                               <C>         <C>           <C>
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.


<PAGE>



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%
----------------------------------------------------------------------------------------- ------------ -------- ------------ -------

<PAGE>



--------------------------------------------------------------------------- ------ ----------- ------- -------------- -----------
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%
=========================================================================== ====== =========== ======= ============== ===========
</TABLE>

       (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.


<PAGE>
<TABLE>
<CAPTION>



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:

<S>                  <C>                          <C>                          <C>                       <C>
  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
                                                  ======                    ======                     ======

</TABLE>



See Notes to Consolidated Financial Statements.



<PAGE>


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.


<PAGE>



         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:
<TABLE>
<CAPTION>

  (Millions of dollars, except per share amounts)                  2002         2001        2000
                                                                   ----         ----        ----

<S>                                                               <C>            <C>        <C>
  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
                                                                  =======       =====       =====
</TABLE>

       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.


<PAGE>



       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.


<PAGE>



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.



<PAGE>


        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.


<PAGE>



        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:


<PAGE>

<TABLE>
<CAPTION>


Components of Net Periodic Benefit Cost (Income)

                                            Retirement Benefits                  Other Postretirement Benefits
                                   --------------------------------------    --------------------------------------

Millions of dollars                    2002            2001        2000          2002          2001        2000
                                       ----            ----        ----          ----          ----        ----

<S>                                     <C>          <C>        <C>               <C>           <C>        <C>
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
</TABLE>



<PAGE>



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.


<PAGE>



      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:
<TABLE>
<CAPTION>

                                       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
------------------- ----------------- ------------------- ------------------------------ ----------------
<S>         <C>        <C>                   <C>                <C>         <C>              <C>
  $25.50 to $29.60     1,717,910             8.4                $27.38      274,306          $26.91
------------------- ----------------- ------------------- ------------------------------ ----------------

</TABLE>
      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:
<TABLE>
<CAPTION>

                                                                   2002             2001             2000
                                                                   ----             ----             ----
<S>                                                              <C>               <C>              <C>
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

</TABLE>
      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.



<PAGE>


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.


<PAGE>


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:
<TABLE>
<CAPTION>

Millions of dollars                                                    2002             2001              2000
----------------------------------------------------------------- --------------- ----------------- -----------------

<S>                                                                    <C>             <C>               <C>
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
================================================================= =============== ================= =================



<PAGE>



       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
----------------------------------------------------------- -------------- -------------- ------------- --------------
</TABLE>

       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.
<TABLE>
<CAPTION>

Investee           Securities                                                      Basis
------------------ ------------------------------------------------------- ----------------------
                                                                           (Millions of dollars)


<S>                <C>                                                               <C>
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
</TABLE>

        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.


<PAGE>



        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.



<PAGE>


        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.
<TABLE>
<CAPTION>

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
------------------------- ---------- ----------- ------------ ---------- ----------- ------------ -------- ------------ ------------

<S>                           <C>           <C>        <C>         <C>         <C>                     <C>       <C>       <C>
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)             -
---------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------
</TABLE>



<PAGE>


       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)

<TABLE>
<CAPTION>

2002                                                              First      Second      Third      Fourth
Millions of dollars, except per share amounts                    Quarter     Quarter    Quarter     Quarter     Annual
-------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------

<S>                                                               <C>         <C>         <C>        <C>        <C>
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
-------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
</TABLE>

(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.


<PAGE>





















                      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



<PAGE>


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.


<PAGE>



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.




<PAGE>



       SCE&G's contractual cash obligations as of December 31, 2002 are
summarized as follows:
<TABLE>
<CAPTION>

                          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
<S>                               <C>          <C>        <C>         <C>           <C>
  (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

</TABLE>
       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.


<PAGE>



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.



<PAGE>


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:
<TABLE>
<CAPTION>

  Classification (in thousands)             2002        % Change        2001        % Change
  ---------------------------------------------------- ------------ ------------- -------------

<S>                                           <C>         <C>         <C>            <C>
  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%)
  ==================================================== ============ ============= =============
</TABLE>

     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.



<PAGE>


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.
<TABLE>
<CAPTION>

December 31, 2002                                                     Expected Maturity Date
Millions of dollars

Liabilities                        2003       2004       2005        2006        2007       Thereafter      Total     Fair Value
-------------------------------- ---------- --------- ----------- ----------- ------------ ------------- ------------ ------------

     Long-Term Debt:
<S>             <C>                <C>       <C>        <C>         <C>           <C>        <C>           <C>          <C>
     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
</TABLE>

   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


<PAGE>


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












<PAGE>
<TABLE>
<CAPTION>


SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS

------------------------------------------------------------------------------------- ---------------- -------------------
December 31, (Millions of dollars)                                                         2002               2001
------------------------------------------------------------------------------------- ---------------- -------------------
Assets
Utility Plant (Note 5):
<S>                                                                                       <C>                <C>
    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
===================================================================================== ================ ===================








<PAGE>


   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.




<PAGE>



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.




<PAGE>


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.


<PAGE>






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.


<PAGE>


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.

</TABLE>

<PAGE>


                   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
============================================================= ===============



<PAGE>



       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.


<PAGE>



       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.



<PAGE>


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.



<PAGE>


       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:
<TABLE>
<CAPTION>

Components of Net Periodic Benefit Cost

                                                  Retirement Benefits                Other Postretirement Benefits
                                           -----------------------------------     ----------------------------------

Millions of dollars                           2002           2001                    2002        2001        2000
                                              ----           ----                    ----        ----        ----
                                                                            2000

<S>                                            <C>         <C>        <C>             <C>          <C>       <C>
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%



<PAGE>


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
</TABLE>

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.


<PAGE>


       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

<TABLE>
<CAPTION>

       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:
<S>                                                 <C>              <C>               <C>
      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
============================================================== ================= =================
</TABLE>
<TABLE>
<CAPTION>

    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
---------------------------------------------------------------- ----------------- ----------------- ------------------

<S>                                                                   <C>               <C>                <C>
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
================================================================ ================= ================= ==================
</TABLE>

       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.



<PAGE>


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:
<TABLE>
<CAPTION>

  Millions of dollars                                                2002                     2001
  ---------------------------------------------------------- ---------------------- --------------------------
                                                                          Estimated                Estimated
                                                              Carrying      Fair       Carrying       Fair
                                                               Amount       Value       Amount       Value
  ---------------------------------------------------------- ----------- ------------ ------------ -----------
  Assets:
<S>                                                            <C>         <C>            <C>         <C>
    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
  ---------------------------------------------------------- ----------- ------------ ------------ -----------
</TABLE>

       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.


<PAGE>



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.


<PAGE>



         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.
<TABLE>
<CAPTION>

Disclosure of Reportable Segments

Millions of dollars
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------
                                   Electric         Gas              All          Adjustments/      Consolidated
              2002                Operations    Distribution        Other         Eliminations          Total
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------

<S>                                 <C>             <C>                                                <C>
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
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------
</TABLE>

         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)

<TABLE>
<CAPTION>

Millions of dollars
-------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
                                                           First        Second        Third       Fourth
2002                                                      Quarter      Quarter       Quarter      Quarter     Annual
-------------------------------------------------------- ----------- ------------- ------------ ------------ ---------

<S>                                                         <C>          <C>          <C>          <C>        <C>
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
-------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
</TABLE>




<PAGE>



















                             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).

<PAGE>


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.


<PAGE>



         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.
<TABLE>
<CAPTION>

                          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
<S>                                 <C>              <C>               <C>              <C>            <C>
  (including interest)              $585             $59               $71              $44            $411
Operating leases                    $ 1              -                $ 1                -               -
Other commercial commitments        $276           $175               $101               -               -

</TABLE>
        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.



<PAGE>


        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.


<PAGE>



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.
<TABLE>
<CAPTION>

  December 31, 2002                                                    Expected Maturity Date
  Millions of dollars

  Liabilities                           2003     2004       2005       2006       2007     Thereafter    Total    Fair Value
  ------------------------------------ ------- ---------- ---------- ---------- ---------- ----------- ---------- ------------

  Long-Term Debt:
<S>            <C>                        <C>      <C>       <C>         <C>        <C>      <C>         <C>         <C>
    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
</TABLE>

        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.


<PAGE>


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






<PAGE>


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

<PAGE>


<TABLE>
<CAPTION>

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS

-------------------------------------------------------------------------------------------- --------------------------
December  31, (Millions of dollars)                                          2002                      2001
-------------------------------------------------------------------------------------------- --------------------------

Assets

<S>                                                                          <C>                       <C>
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.


<PAGE>




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.




<PAGE>


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.


<PAGE>


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.
</TABLE>


<PAGE>





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.)

<PAGE>


         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.


<PAGE>



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:
<TABLE>
<CAPTION>

Millions of Dollars                           Retirement Benefits  Other Postretirement Benefits
                                      --------------------------------------------------------------

Components of Net Periodic Benefit Cost
<S>                                                  <C>                         <C>
             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
                                                    =====

</TABLE>


<PAGE>




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
---------------- ----------------- ------------------ -----------------





<PAGE>


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

<TABLE>
<CAPTION>

       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:
<S>                                                         <C>              <C>             <C>
      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
    --------------------------------------------- -------------- -------------- --------------- --------------
</TABLE>

       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
<TABLE>
<CAPTION>

Millions of dollars
--------------------------------------- -------------------- -------------- --------------------- ---------------
                                                Gas               All           Adjustments/       Consolidated
             2002                          Distribution          Other          Eliminations          Total
--------------------------------------- -------------------- -------------- --------------------- ---------------

<S>                                             <C>                                                    <C>
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
--------------------------------------- -------------------- -------------- --------------------- ---------------



<PAGE>



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.

</TABLE>

<PAGE>




                          PART II, ITEM 9 AND PART III


                                SCANA CORPORATION
                      SOUTH CAROLINA ELECTRIC & GAS COMPANY
             PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED

<PAGE>


     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.


<PAGE>

<TABLE>
<CAPTION>


                                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

<S>                             <C>
       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.




<PAGE>



     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.


</TABLE>


<PAGE>
<TABLE>
<CAPTION>



                                                  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

<S>                         <C>
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

</TABLE>

*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.



<PAGE>


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.
<TABLE>
<CAPTION>

     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                      ($)           ($)             ($)              (#)          ($)            ($)
------------------------------------ ------ --------------- ----------- ------------------ -------------- ----------- --------------

<S>                                  <C>        <C>          <C>             <C>              <C>          <C>             <C>
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
                                                                                                              -
------------------------------------ ------ --------------- ----------- ------------------ -------------- ----------- --------------
</TABLE>

(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.


<PAGE>
<TABLE>
<CAPTION>


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%($)
------------------------- -------------- ----------------- --------------- ---------------- -------------- --------------

<S>                          <C>              <C>              <C>            <C>   <C>       <C>            <C>
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
</TABLE>

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.



<PAGE>





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.



<PAGE>


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.


<PAGE>

<TABLE>
<CAPTION>


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)
                            ---------------------------------                          ---------------------------------
<S>         <C>                          <C>                                                          <C>
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

</TABLE>

*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.


<PAGE>



                    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





<PAGE>
<TABLE>
<CAPTION>


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
<S>               <C>                        <C>              <C>                               <C>              <C>
                  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            -





<PAGE>




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           -






<PAGE>





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.

</TABLE>


<PAGE>


                                   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


<PAGE>



                                   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



<PAGE>


                                   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



<PAGE>


                                  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


<PAGE>


                                  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


<PAGE>



                                  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
<PAGE>



                                  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


<PAGE>


                                  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


<PAGE>



                                  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
<TABLE>
<CAPTION>

                                  EXHIBIT INDEX

                 Applicable to Form 10-K of
Exhibit                                PSNC
No. SCANA SCE&G Energy Description

<C>                                                                                               <C> <C>
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)



<PAGE>


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)



<PAGE>


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)
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                  EXHIBIT INDEX

               Applicable to Form 10-K of
Exhibit                              PSNC
No. SCANA SCE&G Energy Description



<PAGE>


<C>                                                                                                   <C>
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)




<PAGE>


                                  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

</TABLE>