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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-K

                (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                   For the Fiscal Year Ended December 31, 2003

                                       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





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Securities registered pursuant to Section 12(g) of the Act:  None

         Indicate by check mark whether the registrants: (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No

         Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.

         SCANA Corporation  ___
         South Carolina Electric & Gas Company   X
Public Service Company of North Carolina, Incorporated    X


         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          No  X
                                                    -------    -----
         Public Service Company of North Carolina, Incorporated Yes     No  X
                                                                    ----  -----

         The aggregate market value of voting stock held by non-affiliates of
SCANA Corporation was $3.8 billion at June 30, 2003, based on a price of $34.28.
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 13, 2004
      ----------             ---------------------------   --------------------

SCANA Corporation                  Without Par Value          110,731,020

South Carolina Electric
  & 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 2004 Proxy Statement, in connection with its 2004 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).





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                                TABLE OF CONTENTS
                                                                                                               Page
<S>                                                                                                             <C>
DEFINITIONS.............................................................................................        4

PART I

     Item 1.  Business..................................................................................        5

     Item 2.  Properties ...............................................................................      19

     Item 3.  Legal Proceedings.........................................................................      21

     Item 4.  Submission of Matters to a Vote of Security Holders ......................................      23

   Executive Officers of SCANA Corporation..............................................................      24

PART II
     Item 5.  Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
                      Purchases of Equity Securities....................................................      25

     Item 6.  Selected Financial Data...................................................................      26

              SCANA Corporation.........................................................................      27
     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.....................................................     87
     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....................................    131
     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
     Item 9A.   Controls and Procedures.................................................................    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 ...........................................    164

     Item 14.    Principal Accountant Fees and Services.................................................    164

PART IV
     Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .........................    165

SIGNATURES..............................................................................................    169

     Exhibit Index......................................................................................    172
     Certifications Required by Rule 13a-14.............................................................    187
              Certifications Pursuant to 18 U.S.C. Section 1350................................................ 193
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<TABLE>
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                                                        DEFINITIONS

The following abbreviations used in the text have the meanings set forth below
unless the context requires otherwise:

          TERM                                                MEANING
<S>                                                <C>
AFC................................................ Allowance for Funds Used During Construction
CAA................................................Clean Air Act, as amended
DHEC............................................... South Carolina Department of Health and Environmental Control
DOE................................................ United States Department of Energy
DOJ................................................United States Department of Justice
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
IRC................................................Internal Revenue Code, as amended
IRS................................................Internal Revenue Service
KW or KWh.......................................... Kilowatt or Kilowatt-hour
LLC................................................ Limited Liability Company
LNG................................................ Liquefied Natural Gas
MCF................................................ Thousand Cubic Feet
MGP................................................ Manufactured Gas Plant
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
NSR................................................New Source Review
NYMEX..............................................New York Mercantile Exchange
NYSE............................................... New York Stock Exchange
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 SCG Pipeline....................................... SCG Pipeline,
Inc. 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 Summer
Station..................................... V. C. Summer Nuclear Station
Transco............................................ Transcontinental Gas
Pipeline Corporation Williams Station................................... A. M.
Williams Generating Station owned by GENCO WNA Weather Normalization Adjustment

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                                     PART I
<TABLE>
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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 optic telecommunications, ethernet
 -----------
 Generates and sells electricity to wholesale          services and data center facilities and builds,
 and retail customers and purchases, sells and         manages and leases communications towers in
 transports natural gas to wholesale and               South Carolina, North Carolina and Georgia.
 retail customers.                                     Through its Delaware subsidiary,  SCANA
                                                       Communications Holdings, Inc., holds investments
 SOUTH CAROLINA GENERATING                             in telecommunications companies.
 -------------------------
 COMPANY, INC.
 Owns and operates Williams Station and                SCANA ENERGY MARKETING, INC.
                                                       ----------------------------
 sells electricity to SCE&G.                           Markets natural gas, primarily in the Southeast,
                                                       and provides energy-related risk management
 SOUTH CAROLINA FUEL                                   services to producers and customers.  Through its
 --------------------
 COMPANY, INC.                                         SCANA Energy division, markets natural gas in
 -------------
 Acquires, owns and provides financing                 Georgia's retail natural gas market.
 for SCE&G's nuclear fuel, fossil fuel
 and sulfur dioxide emission allowances.               SERVICECARE, INC.
                                                       -----------------
                                                       Provides service contracts on home appliances
 PUBLIC SERVICE COMPANY OF and heating
                                                       and air conditioning units.
 NORTH CAROLINA, INCORPORATED
 Purchases, sells and transports                       PRIMESOUTH, INC.
                                                       ----------------
 natural gas to retail customers.                      Provides management and maintenance services
                                                       for power plants and a synfuel production 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.
 ------------------
 Provides 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 one
     additional company that is 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 or Public Service  Company of North Carolina,
Incorporated or both.

     Commodity  price  changes may affect the  operating  costs and  competitive
positions  of the energy  businesses,  thereby  adversely  impacting  results of
operations, cash flows and financial condition.

         Our energy businesses are sensitive to changes in coal, gas, oil and
other commodity prices. Any changes could affect the prices these businesses
charge, their operating costs and the competitive position of their products and
services. SCE&G is able to recover the cost of fuel used in electric generation
through retail customers' bills, but increases in fuel costs affect electric
prices and, therefore, the competitive position of electricity against other
energy sources. In the case of regulated natural gas operations 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. Increases in gas costs may also result
in lower usage by customers unable to switch to alternate fuels.

     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 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 until August 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,  cash flows
and financial condition.

         Changes in interest rates can affect the cost of borrowing on variable
rate debt outstanding, on refinancing of debt maturities and on incremental
borrowing to fund new investments. 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 investment grade debt ratings. 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.

SCANA may not be able to reduce its leverage as quickly as planned. This could
result in downgrades of SCANA's debt ratings, thereby increasing its borrowing
costs and adversely affecting its results of operations, cash flows and
financial condition.

         SCANA's leverage ratio of debt to capital increased significantly
following its acquisition of PSNC Energy in 2000, and was approximately 60% at
December 31, 2003. SCANA has publicly announced its desire to reduce this
leverage ratio to between 50% to 52%, but SCANA's ability to do so depends on a
number of factors. If SCANA is not able to reduce its leverage ratio, SCANA's
debt ratings may be affected, it may be required to pay higher interest rates on
its long- and short-term indebtedness, and its access to the capital markets may
be limited.

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 the related assets could be required.

     SCANA,  SCE&G and PSNC Energy are subject to risks  associated with changes
in business  climate  which could limit  access to capital,  thereby  increasing
costs and adversely  affecting  results of operations,  cash flows and financial
condition.

         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, cash flows and financial
condition.

         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). We do not hedge the entire exposure of our operations from
commodity price volatility. To the extent we do not hedge against commodity
price volatility or our hedges are not effective, results of operations, cash
flows and financial condition may be diminished.

     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  affecting  results of  operations,  cash flows 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 to 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-2
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 reduced, more extensive permitting requirements are imposed
or additional substances become regulated.

     Changing  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.

            Federal energy legislation and FERC's regulatory initiatives, if
enacted as currently proposed, would bring sweeping changes to the country's
existing regulatory framework governing transmission, open access and energy
markets and would attempt, in large measure, to standardize the national energy
market. 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 of such
standardization and the resultant impact on results of operations, cash flows
and financial condition.

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,
cash flows or financial condition.

        SCANA is a registered holding company under 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,  cash  flows  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.

     Covenants in certain financial instruments may limit SCANA's ability to pay
dividends, thereby adversely impacting the valuation of our common stock and our
access to capital.

         Our assets consist primarily of investments in subsidiaries. Dividends
on our common stock depend on the earnings, financial condition and capital
requirements of our subsidiaries, principally SCE&G 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, cash flows and financial
condition.

         The V.C. Summer nuclear plant, operated by SCE&G, provided
approximately 4.9 million MWh, or 21% of our generation capacity, in 2003. Our
license to operate this plant currently expires in 2022. We have filed an
application with the 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 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, cash flows and financial condition. A
major incident at a nuclear facility anywhere in the world could cause the NRC
to limit or prohibit the operation or licensing of any domestic nuclear unit.
Finally, in today's environment, there is a heightened risk of terrorist attack
on the nation's nuclear facilities, which has resulted in increased security
costs at our nuclear plant.

 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. SCANA and its subsidiaries (the Company) had full-time,
permanent employees as of February 13, 2004 and February 28, 2003 of 5,458 and
5,361, 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 13, 2004 and February 28, 2003 of 2,865 and 2,875,
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 13,
2004 and February 28, 2003 of 775 and 758, respectively.
INVESTOR INFORMATION

       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 or furnished to the SEC are available free of charge through
SCANA's internet website at www.SCANA.com as soon as reasonably practicable
after these reports are filed or furnished. The information found on SCANA's
website is not part of this or any other report filed with or furnished to the
SEC.

SEGMENTS OF BUSINESS

       SCANA does not directly own or operate any physical properties. 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 one other direct, wholly owned subsidiary that is in liquidation.

       Information with respect to major segments of business is contained in
Management's Discussion and Analysis of Financial Condition and Results of
Operations for SCANA and SCE&G and the consolidated financial statements for
SCANA and SCE&G (Note 11) and PSNC Energy (Note 9). 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 higher 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. Resale customers include municipalities, electric cooperatives,
investor-owned utilities and federal and state electric agencies. Predominant
industries in the areas served by SCE&G include synthetic fibers, chemicals,
fiberglass, paper and wood, metal fabrication, stone, clay and sand mining and
processing and textile manufacturing.

       GENCO owns and operates Williams Station and sells electricity solely to
SCE&G.

       Fuel Company acquires, owns and provides financing for SCE&G's nuclear
fuel, fossil fuel and sulfur dioxide emission allowance requirements.

       PSNC Energy is a public utility engaged primarily in purchasing, selling
and transporting natural gas to approximately 394,000 residential, commercial
and industrial customers. PSNC Energy provides service to 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, which became operational in 2003, provides interstate
transportation services for natural gas to southeastern Georgia and South
Carolina. SCG Pipeline transports 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
the pipeline is at the site of the natural gas-fired generating station that
SCE&G is building in Jasper County, South Carolina.

Nonregulated Businesses

       SEMI markets natural gas 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 over 400,000 customers
(as of December 31, 2003) in Georgia's natural gas market. The GPSC regulates
the gas rates charged to approximately 40,000 of these customers who are served
by SCANA Energy as the regulated provider. This group includes low-income and
high credit risk customers. In December 2003 SCANA Energy signed a definitive
agreement with another gas marketer to acquire the approximately 50,000
customers served by that marketer in Georgia. The purchase, which is subject to
customary closing conditions, was approved by the GPSC in January 2004 and is
expected to be completed in March 2004.

       SCI owns and operates a 500-mile fiber optic telecommunications network
and data center facilities in South Carolina and, through its joint venture with
FRC, LLC, has an interest in an additional 460 miles of fiber in South Carolina,
North Carolina and Georgia. SCI also provides ethernet services in South
Carolina, as well as tower site construction, management and rental services in
South Carolina and North Carolina.

       SCH, a Delaware corporation and a wholly owned subsidiary of SCI, holds
investments in ITC^DeltaCom, Inc., Knology, Inc. and Magnolia Holding Company
LLC (Magnolia Holding), which are telecommunications services companies
operating primarily in the southeastern United States. In May 2003 SCH's
investment in ITC Holding Company, Inc. was sold. The transaction resulted in
the receipt of net after-tax cash proceeds of approximately $48 million and the
receipt of an investment interest in a newly formed entity, Magnolia Holding. A
book gain, net of tax, of approximately $39 million was realized upon this
transaction. In 2003 SCH recorded impairment losses on its Knology investment
totaling $34.6 million, net of taxes.

       ServiceCare, Inc. is engaged primarily in providing homeowners with
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 a synfuel
production 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.

     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 Overview 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.

        For a discussion of the impact of various rate matters on the Company's
capital requirements, see the Regulatory Matters section of Management's
Discussion and Analysis of Financial Condition and Results of Operations for
SCANA and SCE&G and Note 2 of the consolidated financial statements for the
Company, SCE&G and PSNC Energy.

       During the three-year period 2004-2006, the Company expects to meet its
capital requirements principally 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 next 12 months and for the foreseeable future.

       For a discussion of cash requirements for construction and nuclear fuel
expenditures, see the Liquidity and Capital Resources section of Management's
Discussion and Analysis of Financial Condition and Results of Operations for
SCANA and SCE&G.

CAPITAL PROJECTS

       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. Costs incurred through December 31, 2003 totaled
approximately $425 million.

       In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam in
order to comply with new federal safety standards. 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, 2003 totaled approximately $169 million.

        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. SCG became operational in November 2003 and
provides interstate transportation services for natural gas to markets in
southeastern Georgia and South Carolina. SCG transports natural gas from
interconnections with Southern Natural at Port Wentworth, Georgia, and from an
import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia.
The endpoint of SCG's pipeline is at the site of the natural gas-fired
generating station that SCE&G is building in Jasper County, South Carolina.
Construction of the 18.2 mile pipeline was completed in November 2003 at a cost
of approximately $30 million.

        In August 2003 SCPC began construction of a pipeline called the South
System Loop. This pipeline will stretch 38.3 miles from SCE&G's Jasper County
generation facility to Yemassee in Hampton County, South Carolina, and will
provide a new supply source to SCPC's current system. Completion of the pipeline
is expected in the first quarter of 2004, at a cost of approximately $25
million.

        For a discussion of contractual cash obligations, financing limits,
financing transactions and other related information, see the Liquidity and
Capital Resources section of Management's Discussion and Analysis of Financial
Condition and Results of Operations for SCANA and SCE&G 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 2.82, 0.53, 4.37,
2.47 and 2.77 for the years ended December 31, 2003, 2002, 2001, 2000 and 1999,
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 before
income taxes. The Company's ratio for 2002 was negatively impacted by the
impairment charge related to the acquisition adjustment associated with PSNC
Energy and the impairments of the Company's investments in certain
telecommunications securities. The ratio for 2001 was positively impacted by the
gain recognized on the exchange of the Company's investment in Powertel, Inc.
for DTAG. For SCE&G these ratios were 3.29, 3.47, 3.78, 4.24 and 3.71 for the
same periods. For PSNC Energy these ratios were 3.37, (7.78), 2.54 and 3.05 for
the years ended December 31, 2003, 2002, 2001 and 2000, respectively, and 3.18
for the fiscal year ended September 30, 1999. 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 before income taxes. PSNC Energy's ratio was negatively
impacted by the impairment charge related to the acquisition adjustment
described above.

ELECTRIC OPERATIONS

Electric Sales

       SCE&G's sales of electricity by class as a percent of total electric
revenues for 2003 and 2002 were as follows:

    ----------------------------------------------------------- ----------------
    CLASSIFICATION                                 2002               2003
    ----------------------------------------------------------- ----------------

    Residential                                     42%                 42%
    Commercial                                      31%                 32%
    Industrial                                      19%                 19%
    Sales for resale                                 4%                  4%
    Other                                            2%                  2%
    ----------------------------------------------------------- ----------------
    Total Territorial                                98%                99%
    NMST                                              2%                  1%
    ----------------------------------------------------------- ----------------
    Total                                          100%               100%
    =========================================================== ================



<PAGE>



         Sales for resale include sales to one municipality and three electric
cooperatives. Sales under the NMST during 2003 include sales to 29
investor-owned utilities and registered marketers, seven electric cooperatives,
five municipalities and three federal/state electric agencies. During 2002 sales
under the NMST included sales to 37 investor-owned utilities and registered
marketers, six electric cooperatives, three municipalities and four
federal/state electric agencies.

         During 2003 the Company recorded a net increase of 10,716 customers,
increasing its total electric customers to 570,940 at year end. The Company's
all-time peak summer demand of 4,404 MW was set on July 30, 2002. The all-time
peak demand of 4,474 MW was set on January 24, 2003.

         For the three-year period 2004-2006, the Company's total territorial
KWh sales of electricity are projected to increase 2.0% annually, assuming
normal weather. The Company's total electric customer base is projected to
increase 1.9% annually. Over the same three-year period, the Company's
territorial peak load (summer, in MW) is projected to increase 2.1% 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
Properties - 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 and
Power Company, Oglethorpe Power Corporation and the Southeastern Power
Administration's Clarks Hill Project. For a discussion of the impact certain
legislative and regulatory initiatives may have on SCE&G's transmission system,
see Electric Operations within the Overview section of Management's Discussion
and Analysis of Financial Condition and Results of Operations for the Company
and SCE&G.

Fuel Costs

         The following table sets forth the average cost of nuclear fuel, coal
and gas and the weighted average cost of all fuels (including oil) used by the
Company for the years 2001-2003.

                                              Cost of Fuel Used
                              --------------------------------------------------
                                   2001             2002             2003
                                   ----             ----             ----
Per MMBTU:
   Nuclear                           $.45             $.50              $.53
   Coal - SCE&G                      1.55             1.65              1.68
   Coal - GENCO                      1.52             1.70              1.75
   Gas - SCE&G                       3.45             3.11              7.02
   Gas - GENCO                       7.11             6.17              7.45
   All Fuels (weighted average)      1.33             1.48              1.58
Per Ton:
   Coal - SCE&G                   $38.70           $41.39            $42.06
   Coal - GENCO                    39.23             43.30            44.30
Per MCF:
    Gas - SCE&G                    $3.56             $3.27            $7.76
    Gas - GENCO                     7.29              6.34              7.71



<PAGE>



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
2001-2003 and the estimates for the years 2004-2006.

                            % of Total MWh Generated
                  --------------------------------------------------------------
                             Actual                          Estimated
                  -------------------------    --------------------------------
                   2001     2002    2003         2004       2005       2006
                   ----     ----    ----         ----       ----       ----

Coal                 75%     70%    70%           63%        64%          61%
Nuclear              21      21     21            20         18          18
Hydro                 4       4       6            5           5           4
Natural Gas & Oil     -       5       3           12         13          17
                  ------------------------- -- ---------- ----------
                  ------------------------- -- ---------- ---------- ----------
                     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, 2003 SCE&G had approximately a 47-day supply of coal in
inventory and GENCO had approximately a 25-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 or when spot market prices are
favorable.

         Contract coal is purchased from seven suppliers located in eastern
Kentucky, Tennessee, West Virginia and southwest Virginia. Contract commitments,
which expire at various times through 2006, are approximately 4.7 million tons
annually, which is 74% of total expected coal purchases for 2004. Sulfur
restrictions on the contract coal range from 1.0% 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)  18-20      2008
  Fabrication   Westinghouse Electric Corporation         18-22      2011

      (1)A region represents approximately one-third to one-half of the nuclear
      core in the reactor at any one time. Region 17 was loaded in 2003. Region
      18 will be loaded in 2005.

      (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
2018 and expects to be able to expand its storage capacity to accommodate the
spent fuel output for the life of Summer Station (including the expected license
extension discussed below) 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. For information regarding the contract and pending
litigation with the DOE for disposal of spent fuel, see Nuclear Fuel Disposal
within the Environmental Matters section of Management's Discussion and Analysis
of Financial Condition and Results of Operations for the Company and SCE&G.

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 Company's and SCE&G's consolidated financial statements.

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 into 2042.

GAS OPERATIONS

Gas Sales - Regulated

         Sales of natural gas by the Company and by regulated subsidiary, by
class as a percent of total gas revenues, for 2003 and 2002 were as follows:

                    The Company          SCE&G               PSNC Energy

CLASSIFICATION      2002    2003     2002        2003       2002        2003
------------------------- ------- -------- ----------- ---------- -----------

Residential        38.3%   41.0%    41.3%       40.5%      60.0%       58.8%
Commercial         21.1%   24.1%    32.8%       32.4%      24.7%       28.3%
Industrial         28.4%   27.7%    24.7%       26.2%       7.2%        7.5%
Sales for Resale    8.3%    4.1%        -           -          -           -
Transportation Gas  3.9%    3.1%     1.2%        0.9%       8.1%        5.4%
                    ----    ----     ----        ----       ----        ----
       Total        100%    100%     100%        100%       100%        100%
========================= ======= ======== =========== ========== ===========

         For the three-year period 2004-2006, the Company's total consolidated
sales of natural gas in DTs are projected to increase 1.1% annually, assuming
normal weather. Residential DT sales are projected to increase 2.1% annually,
commercial sales 1.7% and industrial sales 0.4%. Sales for resale are not
expected to increase significantly. The Company's total consolidated natural gas
customer base is projected to increase 2.6% annually.

        During 2003 the Company recorded a net increase of approximately 15,100
regulated gas customers, increasing its regulated gas customers to approximately
670,700. SCE&G recorded a net increase of approximately 4,300 gas customers,
increasing its total gas customers to approximately 276,000. PSNC Energy
recorded a net increase of approximately 10,800 customers, increasing its total
customers to approximately 394,000.

         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. SCG Pipeline
transports gas to SCE&G's Jasper County generating station.

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 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, and 22.3 MMCF from Southern
Natural and 12.5 MMCF from Transco have been temporarily released to Patriots
Energy Group 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.
In addition, SCE&G, under contract with SEMI, is entitled to receive a daily
contract demand of 120,000 DTs for use in electric generation. SCG transports
the gas to SCE&G under a separate contract.

        During 2003 SCPC's average cost per MCF of natural gas purchased for
resale, including firm service demand charges, was $6.18 compared to $4.40
during 2002. SCE&G's average cost per MCF was $6.84 and $5.32 during 2003 and
2002, 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 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
current 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
1,550 MMCF (liquefied equivalent) of gas were in storage at December 31, 2003.
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
4,000 MMCF of gas were in storage on December 31, 2003.

         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. In addition, in November 2003, PSNC Energy commenced 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 an aggregate daily demand of 30,000 DT.

        During 2003 PSNC Energy's average cost per DT of natural gas purchased
for resale, including firm service demand charges, was $6.80, compared to $5.03
during 2002.

        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, Transco and East Tennessee Natural Gas
Company provide for storage capacity of approximately 12,000 MMCF. Approximately
9,400 MMCF were in storage at December 31, 2003. 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 approximately 100 MMCF per
day. Approximately 540 MMCF (liquefied equivalent) were in storage at December
31, 2003. LNG storage service agreements with Transco, Cove Point LNG and Pine
Needle LNG provide for 1,300 MMCF (liquefied equivalent) of storage space.
Approximately 1,100 MMCF (liquefied equivalent) were in storage at December 31,
2003.

         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 over 400,000 customers (as of December
31, 2003) in Georgia's natural gas market. In December 2003 SCANA Energy signed
a definitive agreement with another gas marketer to acquire the approximately
50,000 customers served by that marketer in Georgia. The purchase, which is
subject to customary closing conditions, was approved by the GPSC in January
2004 and is expected to be completed in March 2004.

        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, apprises the Board of Directors with regard
to the management of risk and brings to the Board's attention any areas of
concern. Written policies define the physical and financial transactions that
are approved, as well as the authorization requirements and limits for
transactions.

REGULATION

         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. Certain subsidiaries of SCANA are regulated by state public service
commissions or FERC as to the following matters.

         SCE&G is subject to the jurisdiction of the SCPSC as to retail electric
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.

         GENCO is subject to the jurisdiction of the SCPSC as to issuance of
securities (other than short-term borrowings) and is subject to the jurisdiction
of FERC as to gas rates, accounting 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.

         SCG Pipeline is subject to the jurisdiction of FERC 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 customers classified as low-income or high credit risk and as
to certain other marketing activities.

         SCE&G and GENCO are subject to regulation under the Federal Power Act,
administered by FERC and DOE, in the transmission of electric energy in
interstate commerce and in the sale of electric energy at wholesale for resale,
as well as with respect to licensed hydroelectric projects and certain other
matters, including accounting. (See the Regulatory Matters section of
Management's Discussion and Analysis of Financial Condition and Results of
Operations for the Company and SCE&G.)


<PAGE>



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 (Lake Murray)           2007       Stevens Creek       2025
      Fairfield Pumped Storage       2020       Neal Shoals         2036
      Parr Shoals                    2020

         In January 2003 SCE&G filed with FERC a motion for a five-year license
extension for the Saluda project at Lake Murray because the FERC-mandated
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. On November 18, 2003, FERC
issued an order extending the Saluda project license until 2010; however,
several requests for rehearing of the order have been filed with FERC and,
therefore, the action is not final. For a discussion of SCE&G's agreement with
FERC related to reinforcing the Lake Murray Dam (related to the Saluda project),
see the previous discussion under Capital Projects and see Liquidity and Capital
Resources in Management's Discussion and Analysis of Financial Condition and
Results of Operations for the Company and SCE&G.

         At the termination of a license under the Federal Power Act, the United
States government may take over the project covered thereby, or FERC may extend
the license or issue a license to another applicant. If the federal government
takes over a project or FERC issues a license to another applicant, the original
licensee is entitled to be paid its net investment in the project, not to exceed
fair value, plus severance damages.

        For a discussion of legislative and regulatory initiatives being
proposed that would affect SCE&G's transmission system, see Electric Operations
within the Overview section of Management's Discussion and Analysis of Financial
Condition and Results of Operations for the Company and SCE&G.

         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.

RATE MATTERS

         For a discussion of the impact of various rate matters, see the
Regulatory Matters section of Management's Discussion and Analysis of Financial
Condition and Results of Operations for the Company and SCE&G, and Note 2 to the
consolidated financial statements for the Company, SCE&G and PSNC Energy.

         SCE&G's and PSNC Energy's gas rate schedules for their residential and
small commercial and small industrial 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 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. In April 2003 the SCPSC approved SCE&G's
request to maintain the fuel component of rates at 1.678 cents per KWh,
effective May 1, 2003.

         SCE&G's gas rate schedules and contracts include mechanisms that allow
it to recover from its customers changes in the actual cost of gas. SCE&G's firm
gas rates allow for the recovery of the cost of gas, based on projections, as
established by the SCPSC 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 purchased gas adjustment for cost recovery and gas purchasing
policies are reviewed annually by the SCPSC. In an order dated August 5, 2003
the SCPSC found that for the period April 2002 through December 2002 SCPC's gas
purchasing policies and practices were prudent and SCPC properly adhered to the
gas cost recovery provisions of its gas tariff.

ENVIRONMENTAL MATTERS

         Federal and state authorities have imposed environmental regulations
and standards relating primarily to air emissions, wastewater discharges and
solid, toxic and hazardous waste management. Developments in these areas may
require that equipment and facilities be modified, supplemented or replaced. The
ultimate effect of these regulations and standards upon existing and proposed
operations cannot be predicted. For a more complete discussion of how these
regulations and standards impact 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 and Note 8A to
the consolidated financial statements for PSNC Energy.

OTHER MATTERS

         With regard to SCE&G's insurance coverage for Summer Station, reference
is made to the consolidated financial statements (Note 10B for the Company and
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. 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 also
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>

<TABLE>
<CAPTION>

ELECTRIC PROPERTIES

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

                                                                                                               Net Generating
                                     Present                                                   Year               Capacity
Facility                        Fuel Capability             Location                        In-Service      (Summer Rating) (MW)
--------                        ---------------             --------                        ----------      --------------------
Steam Turbines
--------------
<S>                        <C>                                                                 <C>                  <C>
Summer                     (1)     Nuclear              Parr, SC                               1984                 644
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
D-Area                     (3)     Coal                 DOE Savannah River Site, SC            1995                   35
Cope                               Coal                 Cope, SC                               1996                 410
Cogen South                          *                  Charleston, SC                         1999                   90
Combined Cycle
--------------
Urquhart                   (4)     Coal/Gas/Oil         Beech Island, SC                    1953/2002               568
Jasper                     (5)     Gas/Oil              Hardeeville, SC                            -                  -
Combustion Turbines (Peaking Units)
Faber Place                        Gas                  Charleston, SC                         1961                    8
Hardeeville                        Oil                  Hardeeville, SC                        1968                  12
Burton                             Gas/Oil              Burton, SC                             1961                  27
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
Hydro
-----
Neal Shoals                                             Carlisle, SC                           1905                     5
Parr Shoals                                             Parr, SC                               1914                    15
Stevens Creek                                           Martinez, GA                           1914                    12
Columbia                   (6)                          Columbia, SC                           1927                     9
Saluda (Lake Murray)                                    Irmo, SC                               1930                    206
Pumped Storage
--------------
Fairfield                                               Parr, SC                               1978                    560
                                                                                                                    ------

                                                                                                                     4,891
</TABLE>

 (1) Represents SCE&G's two-thirds portion of the Summer Station (one-third
 owned by Santee Cooper). (2) The steam unit at Williams Station is owned by
 GENCO. (3) This plant is leased from the DOE and is dedicated to DOE's Savannah
 River Site steam needs. The reported net generating
         capacity for this plant is its expected average hourly output. The
         lease expires on October 1, 2005. Although a formal contract is
         required, DOE has indicated orally and in writing its intention to
         extend the contract with SCE&G to October 1, 2014.
(4)      Two combined-cycle turbines burn natural gas or fuel oil to produce 341
         MW of electric generation and use exhaust heat to replace coal-fired
         steam that powers two 75 MW turbines at the Urquhart Generating
         Station. Unit 3 remains as the only coal-fired steam unit at the site.
(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 operate the plant for the
         City and the City will receive the power 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.


<PAGE>



         SCE&G owns 445 substations having an aggregate transformer capacity of
22.9 million KVA (kilovolt-ampere). The transmission system consists of 3,188
miles of lines, and the distribution system consists of 17,377 pole miles of
overhead lines and 4,587 trench miles of underground lines.

NATURAL GAS PROPERTIES

         SCE&G's natural gas system consists of approximately 13,200 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 244 MMCF of natural gas.

         SCPC's natural gas system consists of approximately 1,970 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 850 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 7,830 miles of distribution mains and related service facilities.
PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the
capacity to regasify approximately 100 MMCF per day. PSNC Energy also owns,
through a wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC,
which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC
Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company,
LLC. Pine Needle owns and operates a liquefaction, storage and regasification
facility in North Carolina.

         SCG Pipeline became operational in November 2003. SCG Pipeline provides
interstate transportation of natural gas from interconnections with Southern
Natural at Port Wentworth, Georgia, and from an import terminal owned by
Southern LNG at Elba Island, near Savannah, Georgia, to the site of the natural
gas-fired generating station that SCE&G is building in Jasper County, South
Carolina. Construction of SCG Pipeline 18.2 mile, 20 inch diameter transmission
pipeline and appurtenant facilities was completed in November 2003.

         In August 2003 SCPC began construction of a pipeline called the South
System Loop pipeline project. This pipeline will stretch 38.3 miles from SCE&G's
Jasper County generation facility to Yemassee in Hampton County, South Carolina,
and will provide a new supply source to SCPC's current system. Completion of the
pipeline is expected in the first quarter of 2004, at a cost of approximately
$25 million.

ITEM 3.  LEGAL PROCEEDINGS

        Certain legal proceedings and environmental and regulatory matters and
uncertainties, some of which remain outstanding at December 31, 2003, are
described below. These issues affect the Company and, to the extent indicated,
they also affect SCE&G or PSNC Energy.

Rate and Other Regulatory Matters

        In May 2002 the SCPSC approved 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 reflected 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. The Consumer Advocate of South Carolina
appealed to the South Carolina Circuit Court (Circuit Court) the portion of the
SCPSC's order related to the recovery of certain purchased power costs. The
appeal is still pending. In January 2003, in conjunction with the approval of a
retail rate increase, the SCPSC deferred action on SCE&G's recovery of certain
purchased power costs pending the resolution of the appeal of the SCPSC's May
2002 order.


<PAGE>



        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, 2003 totaled approximately $169 million.

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 by the
end of 2004, with certain monitoring and other activities continuing until 2007.
As of December 31, 2003, SCE&G has spent approximately $19.7 million to
remediate the Calhoun Park site, and expects to spend an additional $2.2
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. In addition, in March 2003 SCE&G signed a consent agreement with
DHEC related to a site formerly owned by SCE&G. The site contained residue
material that was moved from the Columbia MGP. The removal action for this site
has been completed. SCE&G anticipates that major remediation activities for the
three owned sites will be completed before 2006. As of December 31, 2003, SCE&G
has spent approximately $3.0 million related to these three sites, and expects
to spend an additional $5.0 million.

        PSNC Energy is responsible for environmental cleanup at five sites in
North Carolina on which MGP residuals are present or suspected. PSNC Energy's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
PRPs. PSNC Energy has recorded a liability and associated regulatory asset of
approximately $7.0 million, which reflects the estimated remaining liability at
December 31, 2003. Amounts incurred and deferred to date that are not currently
being recovered through gas rates are approximately $2.2 million. Management
believes that all MGP cleanup costs incurred will be recoverable through gas
rates.

        On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer
Station) filed suit in the Court of Federal Claims against the DOE for breach of
contract. The contract, entered into in 1983, known as the Standard Contract for
Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard
Contract) required the federal government to accept and dispose of spent nuclear
fuel and high-level radioactive waste beginning not later than January 31, 1998,
in exchange for agreed payments fixed in the Standard Contract at particular
amounts. As of the date of filing, the federal government has accepted no spent
fuel from Summer Station or any other utility for transport and disposal, and
has indicated that it does not anticipate doing so until 2010, at the earliest.
As a consequence of the federal government's breach of contract, the plaintiffs
have incurred and will continue to incur substantial costs. There are two
additional causes of action alleged as well - a claim for damages for breach of
the implied covenant of good faith and fair dealing and a takings claim
demanding just compensation for the taking of the plaintiffs' real property
(necessitated by the storage). This lawsuit is one of 48 similar lawsuits
brought by nuclear utilities as of January 29, 2004.

Pending or Threatened Litigation

        In 1999 an unsuccessful bidder for the purchase of propane gas assets of
subsidiaries 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. SCANA is confident in its position and intends to vigorously
defend the lawsuit. SCANA does not believe that the resolution of this issue
will have a material adverse impact on its results of operations, cash flows or
financial condition.

         In 2001 a subsidiary of SCANA entered into, in the ordinary course of
business, a fifteen-year take-and-pay contract with an unaffiliated natural gas
supplier to purchase natural gas beginning in the spring of 2004. In December
2002, as a result of the failure of the supplier and its guarantor to meet
contractual obligations related to credit support provisions, the subsidiary
terminated the contract and the supplier initiated arbitration. In December
2003, an unrelated, creditworthy third party agreed to serve as supplier for the
subsidiary for the fifteen year term with similar terms and conditions and a
lower daily volume, and as a result the arbitration was dismissed and both
parties executed releases of claims.

        A complaint was filed on October 22, 2003 against SCE&G by the State of
South Carolina alleging that SCE&G violates the Unfair Trade Practices Act by
charging municipal franchise fees to some customers residing outside a
municipality's limits. The complaint also alleges that SCE&G failed to obey,
observe, or comply with the lawful order of the SCPSC by charging franchise fees
to those not residing in a municipality. The complaint seeks restitution to all
affected customers and penalties up to $5,000 for each separate violation. SCE&G
is confident of the reasonableness of its actions and intends to mount a
vigorous defense. The allegations contained in this complaint are the subject of
a similar lawsuit that was filed against SCE&G, for which a Motion to Dismiss is
pending. The allegations are also the subject of a purported class action
lawsuit filed on or about December 12, 2003 against Duke Energy Corporation,
Progress Energy Services Company and SCE&G. SCE&G believes that the resolution
of these actions will not have a material adverse impact on its results of
operations, cash flows or financial condition. In addition, SCE&G filed a
petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann.
R.103-836. The petition requests that the SCPSC exercise its jurisdiction to
investigate the operation of the municipal franchise fee collection requirements
applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to
correct any past franchise fee billing errors, to adopt improvements in the
system which will reduce such errors in the future, and to adopt any regulation
which the SCPSC deems just and proper to regulate the franchise fee collection
process.

        On August 21, 2003, SCE&G was served as a co-defendant in a purported
class action lawsuit styled as Collins v. Duke Energy Corporation, Progress
Energy Services Company, and South Carolina Electric & Gas Company, in South
Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The
plaintiffs are seeking damages for the alleged improper use of electric
transmission easements but have not asserted a dollar amount for their claims.
Specifically, the plaintiffs contend that the licensing of attachments on
electric utility poles, towers and other facilities to non-utility third parties
or telecommunication companies for other than the electric utilities' internal
use along the electric transmission line right-of-way constitutes a trespass.
SCE&G is confident of the propriety of its actions and intends to mount a
vigorous defense. SCE&G 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, SCE&G and PSNC Energy are also engaged in various other
claims and litigation incidental to their business operations which management
anticipates will be resolved without material loss to any of them.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

           Not Applicable


<PAGE>



                     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.

<TABLE>
<CAPTION>


  Name                     Age     Positions Held During Past Five Years                                          Dates

<S>                        <C>     <C>                                                                            <C>
  W. B. Timmerman          57      Chairman of the Board, President and Chief Executive Officer                   *-present

  H. T. Arthur             58      President and Chief Operating Officer - SEMI                                   2002-present
                                   Senior Vice President, General Counsel and Assistant Secretary                 *-present

  G.                               J. Bullwinkel 55 President and Chief
                                   Operating Officer - SCPC, SCP Pipeline 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              47      Senior Vice President - Natural Gas Asset and Procurement Management -
                                      SCANA Services                                                              2003-present
                                   Deputy General Counsel and Assistant Secretary - SCANA Services                2000-2003
                                   Attorney                                                                       *-2000

  S. A. Byrne              44      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

  S. K. Jenkins            46      Senior Vice President - Marketing and Communications                           2003-present
                                   Vice President, Marketing - Wireless and Broadband Systems Division -
                                      Motorola, Inc. - Austin, TX                                                 1999-2003
                                   Vice President, Marketing - PrimeCo Personal Communications - Westlake, TX     *-1999

  N. O. Lorick             53      President and Chief Operating Officer - SCE&G                                  2000-present
                                   Vice President - Fossil and Hydro Operations - SCE&G                           *-2000

  K. B. Marsh              48      Senior Vice President and  Chief Financial Officer                             *-present
                                   President and Chief Operating Officer - PSNC Energy                            2001-2003
                                   Controller                                                                     *-2000

  C. B. McFadden           59      Senior Vice President - Governmental Affairs and Economic Development -
                                     SCANA Services                                                               2003-present
        Vice President - Governmental Affairs and Economic Development -
                                      SCANA Services                                                              *-2003

  * Indicates position held at least since March 1, 1999.

</TABLE>


<PAGE>


<TABLE>
<CAPTION>
                                     PART II

   ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY RELATED STOCKHOLDER MATTERS
                   AND ISSUER PURCHASES OF EQUITY SECURITIES

   COMMON STOCK INFORMATION - SCANA Corporation
   ------------------ ------------------------------------------------- ------------------------------------------------
                                            2003                                             2002
                       4th Qtr.    3rd Qtr.     2nd Qtr.     1st Qtr.    4th Qtr.    3rd Qtr.    2nd Qtr.    1st Qtr.
   ------------------ ----------- ----------- ------------- ----------- ----------- ------------ ---------- ------------
   ------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ -----------

   Price Range (NYSE Composite Listing):
<S>                     <C>          <C>         <C>         <C>          <C>         <C>         <C>          <C>
       High             $35.70       $35.23      $35.45      $32.70       $31.00      $31.26      $32.15       $30.66
       Low                32.80       31.89       29.82        28.10       24.80       23.50        29.05       26.26
   ------------------ ------------ ----------- ----------- ------------ ----------- ----------- ------------ -----------
</TABLE>

        The principal market for SCANA common stock is the NYSE, using the
   ticker symbol SCG. The corporate name SCANA is used in newspaper stock
   listings. At February 13, 2004 SCANA common stock totaling 110,731,020 shares
   were held by approximately 38,843 stockholders of record.

        SCANA declared quarterly dividends on its common stock of $.345 per
share and $.325 per share in 2003 and 2002, respectively.

        All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has
   no market. During 2003 and 2002 SCE&G paid $149.3 million and $152.5 million,
   respectively, in cash dividends to SCANA. During 2003 and 2002 PSNC Energy
   paid $18.5 million and $14.5 million, respectively, in cash
   distributions/dividends to SCANA.
<TABLE>
<CAPTION>

   SECURITIES RATINGS (As of February 13, 2004)

                                     -------------------------------------------------- ---------------------------
                          ---------- -------------------------------------------------- ---------------------------
                          SCANA                            SCE&G                               PSNC Energy
                                                  First and
                          Medium-    First        Refunding
<S>     <C>    <C>    <C>    <C>    <C>    <C>
   Rating                 Term       Mortgage     Mortgage     Preferred  Commercial    Senior      Commercial
   Agency                 Notes      Bonds        Bonds        Stock      Paper         Unsecured   Paper
   ------                 -----      -----        -----        -----      -----         ---------   -----

   Moody's                A3            A1           A1        Baa1       P-1           A2          P-1
   Standard  & Poors      BBB+         A-           A-         BBB        A-2           A-          A-2

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

        Each of the ratings above had a "stable" outlook. Additional information
   regarding these debt and equity securities is provided in Notes 4, 5 and 7 to
   the consolidated financial statements for the Company and SCE&G and Notes 4
   and 5 to the consolidated financial statements for PSNC Energy.

       Securities ratings used by Moody's and Standard & Poors are as follows:

     Long-term (investment grade)              Short-term
   --------------------------------- -------------------------------
   ---------------- ---------------- --------------- ---------------
     Moody's (1)        S&P (2)         Moody's           S&P
     -----------        -------         -------           ---
         Aaa              AAA        Prime-1 (P-1)        A-1
         Aa               AA         Prime-2 (P-2)        A-2
          A                A         Prime-3 (P-3)        A-3
         Baa              BBB          Not Prime           B
                                                           C
                                                           D
   ---------------- ---------------- --------------- ---------------

   (1) Additional Modifiers: 1, 2, 3 (Aa to Baa) (2) Additional Modifiers: +/-
   (AA to BBB)

       A security rating should be evaluated independently of other ratings and
   is not a recommendation to buy, sell or hold securities. In addition,
   security ratings are subject to revision or withdrawal at any time by the
   assigning rating organization.

        For a discussion of provisions that could limit the payment of cash
   dividends see Management's Discussion and Analysis of Financial Condition and
   Results of Operations for the Company and SCE&G and Note 6 to the
   consolidated financial statements for the Company and SCE&G.

        For a summary of equity securities issuable under the Company's
   compensation plans at December 31, 2003, see Item 12. Security Ownership of
   Certain Beneficial Owners and Management and Related Stockholder Information.



<PAGE>
<TABLE>
<CAPTION>


ITEM 6.  SELECTED FINANCIAL DATA
                                                                                       SCANA
------------------------------------------------------------------------- ---------- ---------- ---------- ----------- --- -
As of or for the Year Ended December 31,                         2003          2002       2001    2000(1)        1999
------------------------------------------------------------------------- ---------- ---------- ---------- ----------- --- -
                                (Millions of dollars, except statistics and per share amounts)
Statement of Income Data
<S>                                                            <C>          <C>         <C>        <C>         <C>
  Operating Revenues                                           $3,416       $2,954      $3,451     $3,433      $2,078
  Operating Income                                                 551          514        528        554         353
  Other Income (Expense)                                             75                    550         44          90
                                                                            (180)
  Income Before Cumulative Effect of Accounting Change             282                     539        221         179
                                                                             88
  Net Income (Loss)(2)                                             282                     539        250         179
                                                                            (142)

Common Stock Data
  Weighted Average Number of Common Shares
     Outstanding (Millions)                                       110.8                  104.7      104.5       103.6
                                                                            106.0
   Basic and Diluted Earnings (Loss)  Per  Share (2)              $2.54                  $5.15      $2.40       $1.73
                                                                           $(1.34)
   Dividends Declared Per Share of Common Stock                   $1.38                  $1.20      $1.15       $1.32
                                                                            $1.30

Balance Sheet Data
  Utility Plant, Net                                             $6,417     $5,474      $5,263     $4,949      $3,851
  Total Assets                                                    8,449       8,074      7,822      7,427       6,011

  Capitalization:
      Common equity                                              $2,306     $2,177      $2,194     $2,032      $2,099
      Preferred Stock (Not subject to purchase or sinking           106         106        106        106         106
funds)
      Preferred Stock, net (Subject to purchase or  sinking                                 10         10          11
funds)                                                           9            9
      SCE&G  - Obligated Mandatorily Redeemable Preferred
        Securities of SCE&G's Subsidiary Trust, SCE&G Trust I                               50         50          50
                                                                 -           50
      Long-term Debt, net                                         3,225       2,834      2,646      2,850       1,563
------------------------------------------------------------------------- ---------- ---------- ---------- -----------     ---
------------------------------------------------------------------------- ---------- ---------- ----------             --- ---
 Total Capitalization                                           $5,646      $5,176      $5,006     $5,048      $3,829
========================================================================= ========== ========== ========== =========== === ===
Other Statistics (3)
   Electric:
      Customers (Year-End)                                     570,940                 547,388    537,253     523,552
                                                                           560,224
      Total sales (Million KWh)                                  22,516                 22,928     23,352      21,744
                                                                           23,085
      Generating capability - Net MW (Year-End)                   4,880                  4,520      4,544       4,483
                                                                            4,866
      Territorial peak demand - Net MW                            4,474                  4,196      4,211       4,158
                                                                                  4,404
   Regulated Gas:
      Customers (Year-End)                                       670,770                 645,749    637,018     260,456
                                                                             655,669
      Sales, excluding transportation (Thousand Therms)        1,205,730    1,354,400  1,183,463  1,389,975   1,013,083
   Retail Gas Marketing:
      Retail customers (Year-End)                                415,573      374,872    385,581    431,814     430,950
      Firm customer deliveries (Thousand Therms)                 356,256      337,858    359,602    431,115     220,729
   Nonregulated interruptible customer deliveries (Thousand      735,902     852,608   1,119,719  1,506,057   1,226,033
Therms)
-------------------------------------------------------------------------- ---------- ---------- ---------- ----------- --- --
</TABLE>

<TABLE>
<CAPTION>

                                                                              SCE&G
-------------------------------------------------------------- ---------- ---------- --------- ---------- ---------
As of or for the Year Ended December 31,                         2003       2002        2001       2000      1999
-------------------------------------------------------------- ---------- ---------- --------- ---------- ---------
                                             (Millions of dollars, except statistics and per share amounts)
Statement of Income Data
<S>                                                               <C>        <C>       <C>        <C>       <C>
  Operating Revenues                                              $1,832     $1,683    $1,715     $1,669    $1,465
  Operating Income                                                   425        417       428        457       393
  Other Income (Expense)                                              36         37        30         16        12

  Income Before Cumulative Effect of Accounting Change               220        219       222        231       189

  Net Income (Loss)(2)                                               220        219       222        253       189


Common Stock Data
  Weighted Average Number of Common Shares
     Outstanding (Millions)                                          n/a        n/a       n/a        n/a       n/a

   Basic and Diluted Earnings (Loss)  Per  Share (2)                 n/a        n/a       n/a        n/a       n/a

   Dividends Declared Per Share of Common Stock                      n/a        n/a       n/a        n/a       n/a


Balance Sheet Data
  Utility Plant, Net                                              $5,016     $4,287    $3,891     $3,615    $3,501
  Total Assets                                                     6,323      5,546     4,962      4,671     4,404

  Capitalization:
      Common equity                                               $2,043     $1,966    $1,750     $1,657    $1,558
      Preferred Stock (Not subject to purchase or sinking            106        106       106        106       106
funds)
      Preferred Stock, net (Subject to purchase or  sinking            9          9        10         10        11
funds)
      SCE&G  - Obligated Mandatorily Redeemable Preferred
        Securities of SCE&G's Subsidiary Trust, SCE&G Trust I          -         50        50         50        50

      Long-term Debt, net                                          1,943      1,534     1,412      1,267     1,121
-------------------------------------------------------------- ---------- ---------- --------- ---------- ---------
-------------------------------------------------------------- ---------- ---------- --------- ---------- ---------
 Total Capitalization                                             $4,101     $3,665    $3,328     $3,090    $2,846
============================================================== ========== ========== ========= ========== =========
Other Statistics (3)
   Electric:
      Customers (Year-End)                                       570,994    560,248   547,411    537,286   523,581

      Total sales (Million KWh)                                   22,531     23,085    22,928     23,353    21,746

      Generating capability - Net MW (Year-End)                    4,880      4,251     3,905      3,929     3,883

      Territorial peak demand - Net MW                             4,474      4,404     4,196      4,211     4,158

   Regulated Gas:
      Customers (Year-End)                                         276,384    272,053   267,206    266,451   260,348

      Sales, excluding transportation (Thousand Therms)            399,392    398,991   368,632    444,521  414, 800
   Retail Gas Marketing:
      Retail customers (Year-End)                                      n/a        n/a       n/a        n/a       n/a
      Firm customer deliveries (Thousand Therms)                       n/a        n/a       n/a        n/a       n/a
   Nonregulated interruptible customer deliveries (Thousand            n/a        n/a       n/a        n/a       n/a
Therms)
---------------------------------------------------------------- ---------- ---------- --------- ---------- ---------
</TABLE>
(1) Reflects acquisition of PSNC Energy effective January 1, 2000. (2) Reflects
write-down for goodwill impairment in 2002 upon adoption of SFAS 142.
(3) Other Statistics for 2000 exclude the effect of the change in accounting for
unbilled revenues, where applicable.


<PAGE>















                                SCANA CORPORATION









Item 7.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations......................................28

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.........49

Item 8.  Financial Statements and Supplementary Data........................51



<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
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 bySCANA's subsidiaries, (4) the impact of competition
from other energy suppliers, including competition from alternate fuels in
industrial interruptible markets, (5) growth opportunities for SCANA's regulated
and diversified subsidiaries, (6) the results of financing efforts, (7) changes
in SCANA's accounting policies, (8) weather conditions, especially in areas
served by SCANA's subsidiaries, (9) performance and marketability of SCANA's
investments in telecommunications companies, (10) performance of SCANA'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 SCANA's periodic reports filed with
the SEC. SCANA disclaims any obligation to update any forward-looking
statements.

OVERVIEW

        SCANA is a registered holding company under PUHCA. Through its wholly
owned regulated subsidiaries, SCANA is primarily engaged in the generation,
transmission and distribution of electricity in parts of South Carolina and the
purchase, transmission and sale of natural gas in portions of North Carolina and
South Carolina. Through a wholly owned nonregulated subsidiary, SCANA markets
natural gas to retail customers in Georgia and to wholesale customers primarily
in the southeast. Other wholly owned nonregulated subsidiaries hold investments
in the securities of certain telecommunications companies, perform power plant
management and maintenance services, provide service contracts to homeowners on
certain home appliances and heating and air conditioning units, and through a
service company, provide administrative, management and other services to other
subsidiaries of SCANA

        Following are percentages of SCANA's revenues and net income earned by
regulated and nonregulated subsidiaries and the percentage of total assets held
by them.

% of Revenues                   2003          2002              2001
                                ----          ----              ----
Regulated                       73%           75%              68%
Nonregulated                    27%           25%              32%

% of Net Income (Loss)          2003         2002 (1)         2001(2)
                                ----         ----             ----
Regulated                       92%           10%              45%
Nonregulated                      8%         (110%)            55%

% of Assets                     2003          2002            2001
                                ----          ----            ----
Regulated                       93%           91%              85%
Nonregulated                      7%            9%             15%

(1)  In 2002, net income for regulated subsidiaries totaled $13.6 million and
     net loss for nonregulated subsidiaries totaled $155.3 million. Net income
     for regulated subsidiaries included an impairment charge related to the
     acquisition adjustment associated with PSNC Energy ($230 million, net of
     tax). Net loss for nonregulated subsidiaries included impairment charges
     for the Company's telecommunications investments ($189.2 million, net of
     tax), which were partially offset by gains the Company recognized from the
     sale of a radio service network ($9.4 million, net of tax) and the sale of
     DTAG shares ($15.3 million, net of tax). See Results of Operations for more
     information.

(2)  Net income from nonregulated subsidiaries in 2001 was significantly
     impacted by gains the Company recognized from the sale of shares of
     telecommunications investments ($354.4 million, net of tax) and the sale of
     the assets of a subsidiary ($4.7 million, net of tax). These gains were
     partially offset by impairment charges related to telecommunications
     investments, ($35.5 million, net of tax) and other investments ($9.0
     million, net of tax). See Results of Operations for more information.

Electric Operations

        The electric operations segment is comprised of the electric operations
of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation,
transmission and distribution of electricity in South Carolina. At December 31,
2003 SCE&G provided electricity to over 570,000 customers in an area of
approximately 15,000 square miles. GENCO owns and operates a coal-fired
generating 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.

        Operating results for electric operations are primarily driven by
customer demand for electricity, the ability to control costs and allowed rates
to be charged to customers. Embedded in these rates is an allowed regulatory
return on equity, which is currently 12.45%. Demand for electricity is primarily
affected by weather, customer growth and the economy. In addition, significant
legislative and regulatory matters could significantly impact the results of
operations and cash flows for the electric operations segment.

        In South Carolina the state legislature is not actively pursuing
electric restructuring. However, both houses of the U.S. Congress passed energy
legislation in 2003, with the House of Representatives passing an energy
conference report. The Senate failed to pass the conference report due to its
inability to reach a compromise on certain key issues unrelated to utilities. If
a compromise is reached in 2004, such legislation is expected to contain
provisions that would repeal PUHCA and transfer additional regulatory authority
to FERC. This legislation may also impose stringent requirements on retail
electric suppliers to generate electricity from renewable energy resources,
which sources may or may not include hydroelectric generation. In addition,
largely in response to the August 2003 blackout in eight northern states and
parts of Canada, the energy legislation would likely include provisions to
develop and enforce reliability standards for high-voltage transmission systems
and to expedite construction of transmission lines. The Company cannot predict
whether such legislation will be enacted, and if it is, the conditions it would
impose on utilities.

        If the energy legislation stalls in 2004, or if it fails to address
certain issues, FERC is expected to proceed with regulatory initiatives that
would significantly change the country's existing regulatory framework governing
transmission, open access and energy markets and would attempt, in large
measure, to standardize the national energy market. In July 2002 FERC issued a
Notice of Proposed Rulemaking on Standard Market Design (SMD) which FERC
supplemented with the issuance of a "white paper" in April 2003. If implemented,
the proposed rule could 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 FERC's action to
determine potential effects on SCE&G's operations. Additional directives from
FERC are expected, and would likely be significantly influenced by the energy
legislation discussed in the preceding paragraph.

        The North American Electric Reliability Council (NERC) is comprised of
utilities and other market participants who voluntarily develop and comply with
NERC policies and standards which govern the planning and operation of the
nation's interconnected bulk power system (the Grid). Currently these policies
and standards are enforceable only through voluntary compliance by NERC members.
Since the August 2003 blackout, and in response to issues identified during
investigation of the blackout, NERC has been developing additional reliability
standards, policies, and procedures. NERC is working with the regions and
utilities in North America to strengthen existing enforcement and compliance
programs, and is seeking to develop contracts between the regions and utility
members to require compliance with these standards. NERC is also actively
pursuing federal legislation to provide it with the authority to enforce
reliability standards on all market participants, not just utilities. SCE&G
continues to work with NERC and directly with other utilities to develop
additional reliability policies and standards and continues to comply with
NERC's existing policies and standards.



<PAGE>



Gas Distribution

        The gas distribution segment is comprised of the local distribution
operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase,
transmission and sale of natural gas in portions of North Carolina and South
Carolina. At December 31, 2003 this segment provided natural gas to more than
715,000 customers in an area of approximately 34,000 square miles.

        Operating results for gas distribution are primarily influenced by
customer demand for natural gas, the ability to control costs and allowed rates
to be charged to customers. Embedded in these rates is an allowed regulatory
return on equity, which is currently 12.25% for SCE&G and 11.4% for PSNC Energy.
Demand for natural gas is primarily affected by weather, customer growth, the
economy and, for commercial and industrial customers, the availability and price
of alternate fuels. Natural gas competes with electricity, propane and heating
oil to serve the heating and, to a lesser extent, other household energy needs
of residential and small commercial customers. This competition is generally
based on price and convenience. Large commercial and industrial customers often
have the ability to switch from natural gas to an alternate fuel, such as
propane or fuel oil. Natural gas competes with these alternate fuels based on
price. As a result, any significant disparity between supply and demand, either
of natural gas or of alternate fuels, and due either to production or delivery
disruptions or other factors, will affect price and impact the Company's ability
to retain large commercial and industrial customers.

Gas Transmission

       The gas transmission segment is comprised of SCPC. SCPC 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
throughout most of South Carolina.

       Operating results for gas transmission are primarily influenced by
customer demand for natural gas, the ability to control costs and allowed rates
to be charged to customers. Embedded in these rates is an allowed regulatory
return on equity, which for SCPC is currently 12.5% to 16.5%. Demand for natural
gas is primarily affected by the price of alternate fuels and customer growth.
SCPC supplies natural gas to SCE&G for its resale to gas distribution customers
and for certain electric generation needs. SCPC also sells natural gas to large
commercial and industrial customers in South Carolina and faces the same
competitive pressures as the gas distribution segment for these classes of
customers.

Retail Gas Marketing

        SCANA Energy, a division of SEMI, comprises the retail gas marketing
segment. This segment markets natural gas to over 400,000 customers throughout
Georgia. SCANA Energy's competitors include affiliates of other large energy
companies with experience in Georgia's energy market as well as several electric
membership cooperatives. SCANA's ability to maintain its market share depends on
the prices it charges customers relative to the prices charged by its
competitors, its ability to continue to provide high levels of customer service
and other factors. In addition, the pipeline capacity available for SCANA Energy
to serve industrial and other customers is tied to the market share held by
SCANA Energy in the retail market.

        In December 2003 SCANA Energy signed a definitive agreement with another
marketer to acquire the approximately 50,000 retail natural gas customers being
served by that marketer in Georgia. The purchase, which is subject to customary
closing conditions, was approved by the GPSC in January 2004 and is expected to
be completed in March 2004. With this transaction, SCANA Energy's total customer
base will represent about a 30 percent share of the 1.5 million customers in
Georgia's natural gas market. SCANA Energy remains the second largest natural
gas marketer in the state.

        In 2002 SCANA Energy was selected by the GPSC to serve as Georgia's
regulated provider for a two-year period. In this capacity, SCANA Energy serves
low-income customers at a rate subsidized by Georgia's Universal Service Fund,
and extends service to high credit risk customers who have been denied service
by other marketers. At December 31, 2003 SCANA Energy's regulated division
served over 40,000 customers. In 2004 the GPSC may extend SCANA Energy's term
for an additional year (beginning September 1) or may conduct another bidding
process, in which SCANA Energy may participate, to select a regulated provider
for a new term.

        In July 2003 the GPSC approved a joint stipulation between the GPSC
staff, Atlanta Gas Light Company (AGL) and natural gas marketers (excluding
SCANA Energy). The joint stipulation, among other things, reduces the frequency
whereby AGL can recall capacity previously released to the various gas marketers
and streamlines certain gas balancing processes. Though SCANA Energy believes
the joint stipulation will improve operations for itself and the other gas
marketers, SCANA Energy continues to advocate an alternate plan it proposed that
would assign interstate asset capacity to those gas marketers choosing
assignment and approved by the GPSC. The GPSC filed a request with FERC to
obtain a declaratory order on whether FERC regulation would preempt or have
jurisdiction over SCANA Energy's proposal. Comments were due to FERC by December
26, 2003. It is uncertain how long it will take for FERC to issue an order.
However, once an order is issued the GPSC will determine what action, if any,
the GPSC should take on SCANA Energy's proposal.

        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 9 to the
consolidated financial statements.) As a part of this risk management process,
at any given time, a portion of SCANA's projected natural gas needs has been
purchased or otherwise placed under contract. Since SCANA Energy operates in a
competitive market, it may be unable to sustain its current levels of customers
and/or pricing, thereby reducing expected margins and profitability.

Energy Marketing

        The divisions of SEMI, excluding SCANA Energy, comprise the energy
marketing segment. This segment markets natural gas primarily in the southeast
and provides energy-related risk management services to producers and customers.

        The operating results for energy marketing are primarily influenced by
customer demand for natural gas and the ability to control costs. Demand for
natural gas is primarily affected by the price of alternate fuels and customer
growth.

RESULTS OF OPERATIONS

        The Company's reported earnings (loss) are prepared in accordance with
GAAP. Management believes that, in addition to reported earnings (loss) under
GAAP, the GAAP-adjusted net earnings from operations provides a meaningful
representation of the Company's fundamental earnings power and
period-over-period financial performance. A reconciliation of reported (GAAP)
earnings (loss) per share to GAAP-adjusted net earnings from operations per
share is provided in the table below:

Earnings (Loss) and Dividends

        Reported (GAAP) earnings (loss) per share and GAAP-adjusted net earnings
from operations per share of common stock and cash dividends declared for 2003,
2002 and 2001 were as follows:

<TABLE>
<CAPTION>
                                                                        2003           2002          2001
  ----------------------------------------------------------------- -------------- ------------- -------------
  ----------------------------------------------------------------- -------------- ------------- -------------
<S>                                                                     <C>          <C>            <C>
  Reported (GAAP) earnings (loss) per share                             $2.54        $(1.34)        $5.15
      Less: Gains from sales of investments and assets                     .35           .24          3.42
                Investment impairments                                    (.31)        (1.79)         (.42)
                Cumulative effect of accounting change, net of               -         (2.17)             -
  taxes
  ----------------------------------------------------------------- -------------- ------------- -------------
      GAAP-adjusted net earnings from operations per share              $2.50          $2.38        $2.15
  ================================================================= ============== ============= =============
      Cash dividends declared  (per share)                              $1.38          $1.30        $1.20
  ================================================================= ============== ============= =============
</TABLE>

o    2003 vs 2002     GAAP-adjusted net earnings from operations increased $.12
                      primarily due to higher electric margins of $.35,
                      higher gas margins of $.25 and improved results from non-
                      regulated subsidiaries of $.04.  These factors were
                      partially offset by higher operations and maintenance
                      expenses of $.21 (including $.07 due to lower pension
                      income), higher depreciation and amortization expense of
                      $.11, higher property taxes of $.07, lower equity AFC
                      of $.02 and the dilutive effect of additional shares
                      outstanding of $.11.

o                     2002 vs 2001 GAAP-adjusted net earnings from operations
                      increased $.23 primarily due to higher electric margins 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 expenses of
                      $.24 (including $.07 due to lower pension income), lower
                      gas margins of $.15 and higher property taxes of $.07.

         In 2003 the Company recognized a gain of $.35 per share in connection
with the sale of ITC Holding and the receipt of an investment interest in a
newly formed entity (Magnolia Holding). The Company also recorded impairment
charges totaling $.31 per share related to the other than temporary decline in
market value of its investment in Knology.

         In 2002 the Company recorded an impairment charge of $1.72 per share
related to the Company's investment in DTAG. In addition, the Company recorded
an impairment charge of $.07 per share related to its investment in
ITC^DeltaCom. 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 to the 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. In addition, the
Company 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 (which was subsequently sold) of $.04 per share.

Pension Income

         Pension income was recorded on the Company's financial statements as
follows:
<TABLE>
<CAPTION>

Millions of dollars                                                         2003        2002          2001
------------------------------------------------------------------------ ----------- ------------ -------------
------------------------------------------------------------------------ ----------- ------------ -------------
Income Statement Impact:
<S>                                                                        <C>          <C>           <C>
  (Component of) reduction in employee benefit costs                       $(2.3)       $10.9         $22.6
  Other income                                                                7.9        11.1           12.7
Balance Sheet Impact:
  (Component of) reduction in capital expenditures                          (0.5)          3.1           6.2
Component of (reduction in) amount due to Summer Station co-owner           (0.1)          0.7           1.8
------------------------------------------------------------------------ ----------- ------------ -------------
------------------------------------------------------------------------ ----------- ------------ -------------
Total Pension Income                                                        $5.0        $25.8         $43.3
======================================================================== =========== ============ =============
</TABLE>

         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 2003 decreased
significantly compared to 2002 and 2001, primarily as a result of a less
favorable investment market. See also the discussion of pension accounting in
Critical Accounting Policies.

Allowance for Funds Used During Construction (AFC)

         AFC is a utility accounting practice whereby a portion of the cost of
both equity and borrowed funds used to finance construction (which is shown on
the balance sheet as construction work in progress) is capitalized. The Company
includes an equity portion of AFC in nonoperating income and a debt portion of
AFC in interest charges (credits) as noncash items, both of which have the
effect of increasing reported net income. AFC represented approximately 7.2% of
income before income taxes in 2003, 25.8% in 2002 and 3.0% in 2001. The ratio in
2002 was significantly higher than historical norms due to the inclusion in
income before income taxes of $291 million of impairments related to the other
than temporary decline in market value of the Company's investment in DTAG and
ITC^DeltaCom. The ratio in 2001 was lower than historical norms due to the
inclusion in income before income taxes of a gain of $545 million on the
exchange of the Company's investment in Powertel for shares of DTAG.
         In addition to the effect of impairments, the decrease in AFC for 2003
vs 2002 is partially due to the completion of the Urquhart Station repowering
project in June 2002. Also, in January 2003 the SCPSC issued an order allowing
SCE&G to include all Jasper County generating project expenditures as of
December 31, 2002 and other construction work in progress expenditures as of
June 30, 2002 in electric rate base. At the time the expenditures were included
in the rate base, AFC was no longer calculated on those amounts. These decreases
were partially offset by increased AFC from subsequent construction expenditures
related to the Jasper County generating and Lake Murray Dam projects (see
discussion at CAPITAL PROJECTS).

         In addition to the effect of impairments in 2002 and the gain in 2001,
the increase in AFC for 2002 vs 2001 was primarily the result of increased
construction expenditures for the Urquhart Station repowering, Jasper County
generating and Lake Murray Dam projects.

Electric Operations

         Electric Operations is comprised of the electric operations of SCE&G,
GENCO and Fuel Company. Electric operations sales margins for 2003, 2002 and
2001 were as follows:
<TABLE>
<CAPTION>

Millions of dollars                          2003       % Change         2002        % Change         2001
---------------------------------------- ------------- ------------ --------------- ------------ ---------------

<S>                                        <C>             <C>         <C>               <C>        <C>
Operating revenues                         $1,466.5        6.3%        $1,379.5          0.8%       $1,368.7
Less:  Fuel used in generation                 334.1       1.4%            329.6       16.3%            283.3
           Purchased power                       64.0     52.0%             42.1      (69.5%)           138.1
---------------------------------------- -------------              ---------------              ---------------
        Margin                             $1,068.4        6.0%        $1,007.8         6.4%          $947.3
======================================== ============= ============ =============== ============ ===============
</TABLE>

o       2003 vs 2002 Margin increased primarily due to the increase in retail
                     electric base rates approved in January 2003 totaling
                     $63.6 million and customer growth and increased consumption
                     of $24.3 million, partially offset by $27.3 million
                     due to less favorable weather.  Fuel used in generation
                     increased by $9.3 million due to the increased cost of
                     natural gas and fuel oil for the Urquhart combined cycle
                     gas turbines and by $1.1 million due to the increased
                     cost of nuclear fuel, partially offset by $5.5 million due
                     to planned plant outages throughout the year.
                     Purchased Power increased due to planned plant outages
                     throughout the year.

o       2002 vs 2001 Margin increased primarily due to more favorable weather of
                     $31.9 million and customer growth and increased
                     consumption of $30.5 million.  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.

        MWh sales volume by classes, related to the electric margin above, were
as follows:
<TABLE>
<CAPTION>

Classification (in thousands)                   2003        % Change        2002       % Change      2001
-------------------------------------------- ----------- --------------- ----------- ------------ ------------
-------------------------------------------- ----------- --------------- ----------- ------------ ------------

<S>                                             <C>          <C>             <C>        <C>          <C>
Residential                                     6,998        (3.2%)          7,230      11.3%        6,494
Commercial                                      6,607        (0.8%)          6,658       5.9%         6,288
Industrial                                      6,548         0.7%           6,505       2.5%         6,348
Sales for resale (excluding interchange)        1,438        (0.7%)          1,448      30.0%        1,114
Other                                              500       (6.5%)            535       0.2%           534
-------------------------------------------- -----------                 -----------              ------------
                                                                                                  ------------
Total territorial                              22,091        (1.3%)        22,376        7.7%       20,778
NMST                                               425       (40.0%)            709    (67.0%)        2,150
-------------------------------------------- -----------                 -----------              ------------
                                                                                                  ------------
Total                                          22,516        (2.5%)        23,085        0.7%       22,928
============================================ =========== =============== =========== ============ ============
</TABLE>

o    2003 vs 2002    Territorial sales volume decreased primarily due to less
                     favorable weather.  NMST volumes decreased primarily
                     due to planned outages at generation plants that reduced
                     volumes available for resale.

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 beginning in the third quarter of 2002.

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 2003, 2002 and 2001 were as follows:

Millions of dollars               2003    % Change    2002    % Change    2001
--------------------------------------------------------------------------------

Operating revenues               $869.0    32.9%     $653.9    (17.6%)   $793.6
Less: Gas purchased for resale    599.3    49.5%      401.0    (25.4%)    537.8
-----------------------------------------          ----------          ---------
       Margin                    $269.7      6.6%    $252.9     (1.1%)   $255.8
===================================================== ========== ========= =====

o     2003 vs 2002   Margin increased primarily due to customer growth and
                     increased consumption totaling $20.9 million, partially
                     offset by a decrease in industrial usage of $4.1 million
                     primarily due to an unfavorable competitive position of
                     natural gas relative to alternate fuels.

o     2002 vs 2001   Margin decreased primarily as a result of the slowing
                    economy and increased competition with alternate fuels.

      DT sales volume by classes, including transportation gas, were as follows:

Classification (in thousands)  2003    % Change      2002    % Change    2001
------------------------------------- -------- -------- ----------
--------------------------------------------------------------------- ----------

Residential                  38,542      8.0%      35,674   11.6%      31,967
Commercial                   27,715     11.2%      24,927    5.7%      23,583
Industrial                   20,109     (5.4%)     21,247    8.5%      19,578
Transportation gas           25,387   (15.8%)      30,166    7.1%      28,180
Sales for resale                          -                   -              1
                              1                     1
--------------------------------------           ----------           ----------
                                                                      ----------
Total                      111,754      (0.2%)   112,015     8.4%     103,309
======================================= ========= ============ ========== ======

o  2003 vs 2002    Residential and commercial sales volumes increased primarily
                   due to more favorable weather.  Industrial and
                   transportation volumes decreased in 2003 primarily as a
                   result of interruptible customers using their alternate
                   fuel sources during the year.

o  2002 vs 2001    Residential and commercial sales volumes
                   increased primarily due to more favorable weather.
                   Industrial and transportation volumes increased in 2002
                   primarily due to the volatility of the natural gas market
                   in 2001, resulting in interruptible customers using their
                   alternate fuel sources during that year.

Gas Transmission

      Gas Transmission is comprised of the operations of SCPC. Gas transmission
sales margins (including transactions with affiliates) for 2003, 2002 and 2001
were as follows:
<TABLE>
<CAPTION>

Millions of dollars                     2003        % Change        2002        % Change       2001
------------------------------------ ------------ ------------- ------------- ------------- ------------

<S>                                    <C>             <C>         <C>             <C>        <C>
Operating revenues                     $519.8          8.5%        $479.1          0.2%       $478.0
Less: Gas purchased for resale           472.2         6.7%         442.4          1.9%         434.1
------------------------------------ ------------               -------------               ------------
       Margin                            $47.6       29.7%          $36.7       (16.4%)         $43.9
==================================== ============ ============= ============= ============= ============
</TABLE>

o       2003 vs 2002 Margin increased primarily due to the favorable competitive
                     position of natural gas relative to alternate fuels
                     in the first quarter of $13.6 million, partially offset
                     by the unfavorable competitive position of natural gas
                     relative to alternate fuels in the second, third and
                     fourth quarters of $1.5 million.

o       2002 vs 2001 Margin decreased primarily due to the unfavorable
                     competitive position of natural gas relative to alternate
                      fuels in the first quarter of $9.6 million, 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.

     DT sales volume by classes including transportation were as follows:

  Classification (in thousands)2003     % Change   2002     % Change   2001
  ------------------------------------------------------------------------------
  ------------------------------------------------------------------------------

  Commercial                      107     (8.8%)      118   64.6%          71
  Industrial                   31,436    (32.5%)   46,578    59.7%    29,176
  Transportation               12,865      *        3,757    25.8%      2,987
  Sales for resale             47,538   (16.5%)    56,906     8.2%    52,606
  --------------------------------------          ---------           ----------
                                                                      ----------
  Total                        91,946    (14.4%)  107,359    26.5%    84,840
  ==============================================================================
 *Greater than 100%

o       2003 vs 2002 Industrial volumes decreased approximately 6.0 million DTs
                     due to decreased electric generation and
                     approximately 8.8 million DTs due to competitiveness with
                     alternate fuels.  Transportation volumes increased
                     approximately 9.1 million DTs and sales for resale volumes
                     decreased approximately 9.4 million DTs primarily as
                     a result of new transportation contracts with resale
                     customers in 2003.

o       2002 vs 2001 Industrial volumes increased approximately 3.7 million DTs
                     due to increased electric generation and
                      approximately 4.4 million 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.

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 2003, 2002 and 2001 were as follows:

  Millions of dollars      2003     % Change   2002     % Change   2001
  --------------------------------------------------------------------------

  Operating revenues      $448.3     18.1%    $379.5     (16.4%)  $453.8
  Net income                 20.1    40.6%       14.3       *         6.8
  ---------------------------------------------------------------- -------------
 *Greater than 100%

o      2003 vs 2002 Operating revenues increased primarily as a result of higher
                    average retail prices and increased volumes.  Net
                    income increased primarily due to increased margins of $10.8
                    million, partially offset by increased bad debt
                    expense of $3.2 million, increased interest expense of $0.5
                    million and higher operating expense of $0.3 million.

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 a lower effective tax rate of $0.8 million,
                     partially offset by a decrease in gas margin of
                    $2.1 million and higher operating expenses of $0.9 million.

     Delivered volumes for 2003, 2002 and 2001 totaled approximately 35.6
million, 33.8 million and 36.0 million DT, respectively.


<PAGE>



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 2003, 2002 and 2001 were as follows:

  Millions of dollars    2003      % Change   2002      % Change       2001
  ----------------------------------------------------------------- ------------

  Operating revenues    $415.7       31.2%   $316.8      (48.4%)      $613.4
  Net income (loss)         (1.1)  (37.5%)       (0.8)      *              3.4
  ----------------------------------------------------------------- ------------
*Greater than 100%

o       2003 vs 2002 Operating revenues increased $98.9 million which reflects a
                     $146.0 million increase due to higher natural gas
                      prices and a $45.9 million decrease due to lower volumes.
                      Net loss increased primarily due to lower margins of
                      $2.5 million partially offset by lower operating expenses
                      of $2.3 million.

o       2002 vs 2001 Operating revenues decreased primarily due to lower natural
                     gas prices and lower volumes.  Net income decreased
                     $4.2 million which reflects decreases of $5.3 million due
                     to the  closing of SCANA Energy Trading, LLC and $1.7
                     million due to lower margins, partially offset by increases
                     of $1.3 million due to the closing of the
                     unprofitable Midwest office in 2001 and $1.5 million due to
                     lower bad debt expense.

         Delivered volumes for 2003, 2002 and 2001 totaled approximately 73.6
million, 86.2 million and 114.6 million DT, respectively. Delivered volumes
decreased in 2003 compared to 2002 by approximately 2.7 million DT due to
decreased industrial usage and by approximately 9.8 million DT due to fewer
customers caused by a sluggish economy and related customer credit constraints.
Delivered volumes decreased in 2002 compared to 2001 primarily due to the
closing of SCANA Energy Trading, LLC and the Midwest office in 2001.

Other Operating Expenses

         Other operating expenses were as follows:

Millions of dollars                2003    % Change    2002   % Change    2001
------------------------------------------ -------------------------------------

Other operation and maintenance   $558.3    6.9%   $522.2       8.6%    $480.8
Depreciation and amortization      238.3    8.3%     220.0     (1.7%)    223.8
Other taxes                        139.2     9.7%   126.9      10.1%     115.3
                                                                       ---------
------------------------------------------        ----------           ---------
Total                             $935.8    7.7%   $869.1       6.0%    $819.9
========================================== =====================================

o     2003 vs 2002 Other operation and maintenance expenses increased primarily
                   due to lower pension income of $13.2 million,
                   increased labor and benefit costs of $8.3 million, increased
                   bad debt expense of $6.5 million, increased nuclear
                   operating expenses of $4.5 million and increased other
                   operating expenses of $3.6 million.  Depreciation and
                   amortization increased by $11.4 million due to normal net
                   property additions, by $4.2 million due to the
                   completion of the Urquhart Station repowering project in
                   June 2002 and by $2.7 million due to amortization of
                   franchise fees.  Other taxes increased primarily due to
                   increased property taxes.

o     2002 vs 2001 Other operation and maintenance expenses increased primarily
                   due to lower pension income of $11.6 million,
                   increased labor and benefit costs of $19.2 million, increased
                   nuclear refueling maintenance costs 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 to the
                   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.
Other Income

         Components of other income, excluding the equity component of AFC, were
as follows:

Millions of dollars          2003    % Change  2002     % Change  2001
---------------------------------------------------------------------------

Gain on sale of investments   $59.8     *       $23.6    (95.7%) $545.3
Gain on sale of assets           1.2 (92.7%)     16.4     33.3%     12.3
Impairment of investments     (53.1) (81.7%)   (290.7)      *      (61.9)
Other income                   47.9    (0.8%)     48.3    21.7%     39.7
------------------------------------         ----------         -----------
                                                                -----------
Total                        $55.8      *    $(202.4)       *    $535.4
===========================================================================
*Greater than 100%

        A $59.8 million gain on sale of investments was recognized in 2003 in
connection with the sale of ITC Holding and the receipt of an investment
interest in a newly formed entity (Magnolia Holding). In 2002 $23.6 million was
recognized upon the sale of the Company's DTAG stock. Gain on sale of assets in
2002 included the sale of the Company's radio system to Motorola. Impairments
recorded in 2002 included those related to DTAG and ITC^DeltaCom, while
impairments in 2003 related solely to the investment in Knology.

Interest Expense

        Components of interest expense, excluding the debt component of AFC,
were as follows:

  Millions of dollars                2003    % Change  2002    % Change  2001
  ------------------------------------------------------------------------------

  Interest on long-term debt, net   $205.2     0.1%   $205.0     (8.4%) $223.8
  Other interest expense                5.8   (4.9%)      6.1  (39.6%)     10.1
  ------------------------------------------          ---------        ---------
                                                                       ---------
      Total                         $211.0    (0.1%)  $211.1     (9.8%) $233.9
  ==============================================================================

o  2003 vs 2002   Interest expense remained flat due to an $8.5 million decreas
                  e as a result of lower interest rates (including the effect of
                  swaps) which was partially offset by an $8.3 million increase
                  due to additional borrowings.

o  2002 vs 2001   Interest expense decreased by $20.8 million as a result of
                  lower interest rates and by $1.4 million due to lower
                  amortization of debt expense which occurred as a result of
                  debt reduction.

Income Taxes

        Income taxes increased approximately $98.9 million in 2003 compared to
2002 and decreased approximately $268.7 million in 2002 compared to 2001.
Changes in income taxes are primarily due to changes in Other Income described
above. The Company's effective tax rate for 2003 was approximately 31.7%, which
reflects the impact of 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. The Company's effective tax rate has also
been favorably impacted in recent years by the flow-through of federal
investment tax credits and the recovery of the equity portion of AFC.

LIQUIDITY AND CAPITAL RESOURCES

        Cash requirements for SCANA's regulated subsidiaries arise primarily
from their operational needs, funding their construction programs and payment of
dividends to SCANA. The ability of the regulated subsidiaries to replace
existing plant investment, as well as to expand to meet future demand for
electricity and gas, will depend on their ability to attract the necessary
financial capital on reasonable terms. Regulated subsidiaries recover the costs
of providing services through rates charged to customers. Rates for regulated
services are generally based on historical costs. As customer growth and
inflation occur and these subsidiaries continue their ongoing construction
programs, rate increases will be sought. The future financial position and
results of operations of the regulated subsidiaries will be affected by their
ability to obtain adequate and timely rate and other regulatory relief, if
requested.

       The Company's leverage ratio of debt to capital increased significantly
in 2000, when SCANA issued $700 million of long-term debt in connection with the
purchase of PSNC Energy. At December 31, 2003 the leverage ratio was 60%. The
Company's goal is to reduce this leverage ratio to between 50% to 52%. If the
agencies rating the Company's credit determine that the Company will not be able
to achieve sufficient improvement in the leverage ratio, these rating agencies
may downgrade the Company's debt. Such a downgrade would adversely affect the
interest rate the Company may obtain when issuing debt and would increase the
rates applicable to the Company's short-term commercial paper programs. In order
to bring the leverage ratio in line with rating agency expectations, the Company
may apply cash flows from operations, sell equity securities, pay down debt with
proceeds from the sale of telecommunications investments, or a combination of
the three. In addition, SCE&G anticipates finishing construction on its Jasper
County generating station and placing it in commercial operation in mid-2004.
Once the plant is complete, SCE&G's capital expenditure budget is expected to
decline significantly.

       The Company's current estimates of its cash requirements for construction
and nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 2004-2006 are as follows:

---------------------------------------- -------------- --------------
Type of Facilities             2004          2005           2006
------------------             ----          ----           ----
                                     (Millions of dollars)
SCE&G:
  Electric Plant:
       Generation              $197           $52           $135
       Transmission              45             51             42
       Distribution             105           113            119
       Other                     14             13             12
   Nuclear Fuel                  22              5             31
   Gas                           23             21             23
   Common                        58             16             16
   Other                           2             2               -
---------------------------------------- -------------- --------------
       Total SCE&G              466           273            378
PSNC Energy                      50             53             53
Other Companies Combined         66             32             44
---------------------------------------- -------------- --------------
                Total          $582          $358           $475
---------------------------------------- -------------- --------------
<TABLE>
<CAPTION>

       The Company's contractual cash obligations as of December 31, 2003 are
summarized as follows:

                          Contractual Cash Obligations

                                                          Less than                                             After
December 31, 2003                           Total           1year           1-3 years         4-5 years        5 years
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
(Millions of dollars)

Long-term and short-term
<S>                                         <C>               <C>             <C>                 <C>          <C>
  debt  (including interest)                $6,411            $626            $1,107              $562         $4,116
Capital leases                                     2               1                 1                 -              -
Operating leases                                  71             17                36                18               -
Purchase obligations                            221              78               143                  -              -
Other commercial commitments                  6,776          1,271             1,500                726          3,279
                 Total                     $13,481         $1,993             $2,787            $1,306         $7,395

</TABLE>
        Included in other commercial commitments are estimated obligations under
forward contracts for natural gas purchases. Many of these forward contracts
include customary "make-whole" or default provisions, but are not considered to
be "take-or-pay" contracts. Certain of these contracts relate to regulated
businesses; therefore, the effects of such contracts on fuel costs are reflected
in electric or gas rates. Also included in other commercial commitments is a
15-year "take-and-pay" contract for natural gas beginning in the spring of 2004,
estimated obligations for coal supply purchases and certain obligations related
to the Lake Murray Dam reinforcement project.

        Included in purchase obligations are customary purchase orders under
which the Company has the option to utilize certain vendors without the
obligation to do so. The Company may terminate such purchase obligations without
penalty.

        In addition to the contractual cash obligations above, the Company
sponsors a noncontributory defined benefit pension plan and an unfunded health
care and life insurance benefit plan for retirees. The pension plan is
adequately funded, with no contributions having been required since 1997. No
further contributions are anticipated until after 2008. Cash payments under the
health care and life insurance benefit plan were approximately $13 million in
2003, and similar payments are expected in the future.

        In addition, the Company is party to certain NYMEX futures contracts for
which any unfavorable market movements through December 31, 2003 are funded in
cash. These derivatives are accounted for as cash flow hedges under SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended, and
their effects are reflected within other comprehensive income until the
anticipated sales transactions occur.

        The Company also has nuclear fuel obligations that are not listed in the
contractual cash obligations above. While no specific monetary amount is
specified for nuclear fuel contracts, the Company's two-thirds share of expected
cost is $22.2 million for the year 2004, a total of $54.6 million for the years
2005-2007, a total of $11.9 million for the years 2008-2009 and a total of $20.0
million for the years 2010-2011.

         The Company also has a legal obligation associated with the
decommissioning and dismantling of Summer Station that is not listed in the
contractual cash obligations above. See Note 1 to the Company's consolidated
financial statements.

         The Company anticipates that its contractual cash obligations will be
met through internally generated funds and the incurrence of additional
short-term and long-term indebtedness. 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.

        Cash outlays for 2004 (estimated) and 2003 (actual) for certain
expenditures are as follows:

Millions of dollars                                             2004      2003
--------------------------------------------------------------------------------

Property additions and construction expenditures, net of AFC    $559      $725
Nuclear fuel expenditures                                          22        25
Investments                                                        23        17
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
       Total                                                    $604      $767
================================================================================

         Included in cash outlays are the following specific projects:

o         FERC mandated that SCE&G's Lake Murray Dam be reinforced to comply
          with new federal safety standards. Construction for the project and
          related activities is expected to be complete in 2005 at a cost of
          approximately $275 million, of which approximately $169 million had
          been incurred through December 31, 2003.

o         Construction continues on SCE&G's 875 MW generation plant in Jasper
          County, South Carolina. The plant is expected to begin commercial
          operation in mid-2004 and cost approximately $450 million, of which
          approximately $425 million had been incurred through December 31,
          2003.

o         SCG Pipeline completed construction of an 18.2 mile pipeline in
          November 2003 at a cost of approximately $30 million. The pipeline
          will be used to transport natural gas from Port Wentworth and Elba
          Island, Georgia, to SCE&G's new generation plant in Jasper County,
          South Carolina.

o         In August 2003 SCPC began construction of the South System Loop. This
          pipeline will stretch 38.3 miles from SCE&G's Jasper County generating
          facility to Yemassee in Hampton County, South Carolina, and will
          provide a new supply source to SCPC's current system. Completion of
          the pipeline is expected in the first quarter of 2004 at a cost of
          approximately $25 million.



<PAGE>



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.

       At December 31, 2003 SCANA, SCE&G and PSNC Energy had available the
following lines of credit and short-term borrowings outstanding:

(Millions) SCANA SCE&G PSNC Energy
--------------------------------------------------- ---------------------------
--------------------------------------------------- ---------------------------
Lines of credit:
   Committed                              $100           $400         $125
   Uncommitted                             113 (1)          78          -
                                                         (1)
Short-term borrowings outstanding:
   Commercial paper (270 or fewer days)       -          140          55
   Weighted average interest rate             -          1.15%      1.17%

(1) Includes a $78 million uncommitted line that either SCANA or SCE&G
may use.

        In addition, SCE&G has a three-year revolving line of credit totaling
$75 million, expiring in 2005, that provides backup liquidity.

        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.

        South Carolina Electric & Gas Company

        SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945
(Old Mortgage) and covering substantially all of its properties, prohibits the
issuance of additional bonds (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, 2003 the
Bond Ratio was 5.08. 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 $1,279
million at December 31, 2003), (ii) retirements of Class A Bonds (which
retirement credits totaled $156.9 million at December 31, 2003), 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, 2003 approximately $924.6 million 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, 2003 the New Bond Ratio was 4.87.

       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, 2003, the Preferred Stock Ratio was 1.55.

       The Articles also require the consent of a majority of the total voting
power of SCE&G's preferred stock before SCE&G may issue or assume any unsecured
indebtedness if, after such issue or assumption, the total principal amount of
all such unsecured indebtedness would exceed ten percent of the aggregate
principal amount of all of SCE&G's secured indebtedness and capital and surplus
(the ten percent test). No such consent is required to enter into agreements for
payment of principal, interest and premium for securities issued for pollution
control purposes. At December 31, 2003 the ten percent test would have limited
issuances of unsecured indebtedness to approximately $413.5 million. Unsecured
indebtedness at December 31, 2003 totaled approximately $94.4 million, and was
comprised of short-term borrowings.

       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, 2003 SCE&G had not borrowed
under the agreement, but expects to fully draw these amounts in 2004. Any such
amounts would be included in the ten percent test.

      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 regulatory approval, the Indenture under which they are
issued contains no specific limit on the amount which may be issued.

Financing Cash Flows

      During 2003 the Company experienced net cash outflows related to financing
activities of approximately $105 million primarily due to the reduction of long-
and short-term debt and payment of dividends. Conversely, SCE&G experienced net
cash inflows related to financing activities of approximately $106 million
primarily arising from borrowings in support of SCE&G's construction program and
for general corporate purposes.

      The Company uses interest rate swap agreements to manage interest rate
risk. These swap agreements provide for the Company to pay variable and receive
fixed rate interest payments and are designated as fair value hedges of certain
debt instruments. The Company may terminate a swap agreement and may replace it
with a new swap also designated as a fair value hedge. Payments received upon
termination of such swaps are recorded as basis adjustments to long-term debt
and are amortized as reductions to interest expense over the term of the
underlying debt. At December 31, 2003 the estimated fair value of the Company's
swaps totaled $6.3 million (gain) related to combined notional amounts of $333.1
million.

      In anticipation of the issuance of debt, the Company may use interest rate
lock or similar agreements to manage interest rate risk. Payments received or
made upon termination of such agreements are recorded within other deferred
debits or credits on the balance sheet and are amortized to interest expense
over the term of the underlying debt. In connection with the issuance of First
Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon
the termination of a treasury lock agreement. In connection with the issuance of
First Mortgage Bonds in December 2003, the Company paid approximately $3.5
million upon the termination of a forward starting interest rate swap.

      On February 11, 2004 GENCO issued $100 million of senior secured
promissory notes maturing February 1, 2024 and bearing a fixed interest rate of
5.49%. Proceeds from this issuance will be used to support GENCO's construction
program and to repay intercompany advances borrowed for that purpose.

      On February 19, 2004 SCANA increased the quarterly cash dividend rate on
SCANA common stock to $.365 per share, an increase of 5.8%. The new dividend is
payable April 1, 2004 to stockholders of record on March 10, 2004.

      For additional information on significant financing transactions, see the
Consolidated Statements of Capitalization and Note 4 to the consolidated
financial statements for the Company.


<PAGE>



ENVIRONMENTAL MATTERS

Capital Expenditures

      In the years 2001 through 2003, the Company's capital expenditures for
environmental control totaled approximately $227.5 million. These expenditures
were in addition to expenditures included in "Other operation and maintenance"
expenses, which were approximately $29.2 million, $29.9 million, and $23.0
million during 2003, 2002 and 2001, respectively. It is not possible to estimate
all future costs related to environmental matters, but forecasts for capitalized
environmental expenditures for the Company are $41.2 million for 2004 and $207.7
million for the four-year period 2005 through 2008. These expenditures are
included in the Company's construction program, discussed in Liquidity and
Capital Resources and include the matters discussed below.

Electric Operations

      The 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 had indicated that it
would finalize regulations by December 2004 for stricter limits on mercury and
other pollutants generated by coal-fired plants.

      The EPA has undertaken an aggressive enforcement initiative against the
utilities industry, and the DOJ has brought suit against a number of utilities
in federal court alleging violations of the CAA. At least two of these suits
have either been tried or have had substantive motions decided - one favorable
to the industry and one not. Neither is binding as precedent on the Company.
Prior to the suits, those utilities had received requests for information under
Section 114 of the CAA and were issued Notices of Violation. The basis for these
suits is the assertion by the EPA that maintenance activities undertaken by the
utilities over the past 20 or more years constitute "major modifications" which
would have required the installation of costly Best Available Control Technology
(BACT). SCE&G and GENCO have received and responded to Section 114 requests for
information related to Canadys, Wateree and Williams Stations. The regulations
under the CAA provide certain exemptions to the definition of "major
modifications," including an exemption for routine repair, replacement or
maintenance. On October 27, 2003 EPA published a final revised NSR rule in the
Federal Register with an effective date of December 26, 2003. The new rule
represents an industry-favorable departure from certain positions advanced by
the federal government in the NSR enforcement initiative. However, on motion of
several Northeastern states, the United States Circuit Court of Appeals for the
District of Columbia stayed the effect of the final rule. The ultimate
application of the final rule to the Company is uncertain. The Company has
analyzed each of the activities covered by the EPA's requests and believes each
of these activities is covered by the exemption for routine repair, replacement
and maintenance under what it believes is a fair reading of both the prior
regulation and the contested revised regulation. The regulations also provide an
exemption for an increase in emissions resulting from increased hours of
operation or production rate and from demand growth. The current state of
continued DOJ enforcement actions is the subject of speculation industry-wide,
but it is possible that the EPA will commence enforcement actions against SCE&G
and GENCO, and the EPA has the authority to seek penalties at the rate of up to
$27,500 per day for each violation. The EPA also could seek installation of BACT
(or equivalent) at the three plants. The Company believes that any enforcement
actions relative to the Company's, SCE&G's or GENCO's compliance with the CAA
would be without merit. However, if successful, such actions could have a
material adverse effect on the Company's financial condition, cash flows and
results of operations. To comply with current and anticipated state and federal
regulations, SCE&G and GENCO expect to incur capital expenditures totaling
approximately $204.3 million over the 2004-2008 period to retrofit existing
facilities, with increased operation and maintenance costs of approximately $2.3
million per year. To meet compliance requirements for the years 2009 through
2013, the Company anticipates additional capital expenditures totaling
approximately $92.7 million.

      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 2004. 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
financial condition, results of operations and cash flows of the Company, SCE&G
and GENCO.

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 2018 and
expects to be able to expand its storage capacity to accommodate the spent
nuclear fuel output for the life of the plant through 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.

        On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer
Station) filed suit in the Court of Federal Claims against the DOE for breach of
the above contract. The contract known as the Standard Contract for Disposal of
Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract)
required the federal government to accept and dispose of spent nuclear fuel and
high-level radioactive waste beginning not later than January 31, 1998, in
exchange for agreed payments fixed in the Standard Contract at particular
amounts. As of the date of filing, the federal government has accepted no spent
fuel from Summer Station or any other utility for transport and disposal, and
has indicated that it does not anticipate doing so until 2010, at the earliest.
As a consequence of the federal government's breach of contract, the plaintiffs
have incurred and will continue to incur substantial costs. There are two
additional causes of action alleged as well - damages for breach of the implied
covenant of good faith and fair dealing and a takings claim demanding just
compensation for the taking of the plaintiffs' real property (necessitated by
the storage). This lawsuit is one of 48 similar lawsuits brought by nuclear
utilities as of January 29, 2004.

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 $10.9 million and $17.9 million at
December 31, 2003 and 2002, 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 by the end of 2004, with certain monitoring and other
        activities continuing until 2007. As of December 31, 2003, SCE&G has
        spent approximately $19.7 million to remediate the Calhoun Park site,
        and expects to spend an additional $2.2 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. In addition, in March 2003
        SCE&G signed a consent agreement with DHEC related to a site formerly
        owned by SCE&G. The site contained residue material that was moved from
        the Columbia MGP. The removal action for this site has been completed.
        SCE&G anticipates that major remediation activities for the three owned
        sites will be completed before 2006. As of December 31, 2003, SCE&G has
        spent approximately $3.0 million related to these three sites, and
        expects to spend an additional $5.0 million.

        In addition, PSNC Energy is responsible for environmental cleanup at
five sites in North Carolina on which MGP residuals are present or suspected.
PSNC Energy has recorded a liability and associated regulatory asset of
approximately $7.0 million, which reflects the estimated remaining liability at
December 31, 2003. Amounts incurred and deferred to date that are not currently
being recovered through gas rates are approximately $2.2 million. Management
believes that all MGP cleanup costs incurred will be recoverable through gas
rates.

REGULATORY MATTERS

         Material retail rate proceedings are described in more detail in Note 2
to the Company's consolidated financial statements.

South Carolina Electric & Gas Company

        SCE&G is subject to the jurisdiction of the SCPSC as to retail electric
and gas rates, service, accounting, issuance of securities (other than
short-term borrowings) and other matters.

         In conjunction with a January 2003 order, the SCPSC allowed SCE&G to
include all Jasper County generating station project expenditures as of December
31, 2002 and other construction work in progress expenditures as of June 30,
2002 in electric rate base. Once this generating station is complete, SCE&G may
seek to include the remaining project expenditures in its electric rate base.
Construction expenditures for the Lake Murray Dam construction project, which
totaled approximately $169 million as of December 31, 2003, have not been
included in electric rate base. When the Lake Murray project is completed in
2005, SCE&G will determine whether to seek inclusion of such expenditures in
electric rate base.

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, 2003 is approximately $2.5 million, and through December 31, 2003,
they have generated and passed through to SCE&G approximately $97.4 million in
such tax credits. At December 31, 2003 SCE&G has recorded on its balance sheet
$66.6 million net deferred fuel tax benefits, which include partnership losses,
net of tax. In addition, Primesouth, Inc., a non-regulated subsidiary of SCANA,
operates a synthetic fuel facility for a third party and receives management
fees, royalties and expense reimbursements related to these services. Primesouth
does not benefit from any synfuel 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,
net of partnership losses and other expenses, 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 to the consolidated financial
statements.

          The IRS has completed and closed examinations of the Company's
consolidated federal income tax returns through its tax year ended in 2000, with
the exception of the Company's interest in the synthetic fuel partnership, S. C.
Coaltech No. 1 L.P. The IRS has notified the Company that it is in the process
of closing this partnership examination with no changes being proposed, and that
a formal closing letter is forthcoming. The IRS audit report makes no challenge
to the declaration that the synthetic fuel facility was properly placed in
service, and takes no issue with evidence submitted demonstrating that the
facility produces a qualifying fuel.

          On October 29, 2003, the IRS issued Announcement 2003-70 stating that
it had completed a review of chemical change issues associated with tax credits
claimed under IRC Section 29 relating to the production and sale of synthetic
fuel. It further stated that it would resume the issuance of private letter
rulings (PLRs) concerning synthetic fuel credits consistent with the guidelines
regarding chemical change previously set forth in Revenue Procedures 2001-30 and
2001-34 and certain additional requirements related to sampling, testing and
recordkeeping procedures, even though the IRS has indicated that the level of
chemical change required under that guidance is not sufficient for IRC Section
29 purposes. The IRS also stated in the announcement that it would continue to
issue PLRs because it recognized that many taxpayers and their investors have
relied on its long standing ruling practice to make investments. In Announcement
2003-46 issued on June 27, 2003, the IRS had questioned the validity of certain
test procedures and results that had been presented to it by taxpayers with
interests in synfuel operations as evidence that the required significant
chemical change had occurred, and had initiated a review of these test
procedures and results which was completed as noted in Announcement 2003-70.

          Separately, the Permanent Subcommittee on Investigations of the
Government Affairs Committee of the United States Senate (Subcommittee) is
conducting an investigation of potential abuses of tax credits by producers of
synthetic fuel under IRC Section 29. The Subcommittee Chairman, in a memorandum
commencing the investigation, has stated that he anticipates the investigation
will focus on whether certain synthetic fuel producers are claiming tax credits
even though their product is not a qualified synthetic fuel under Section 29 and
IRS regulations. The memorandum also states that the investigation will address
whether certain corporations are engaging in transactions solely to take
advantage of unused Section 29 credits with no other business purpose, and the
IRS' efforts to curb abuses related to these credits.

         While the effect of these two developments is not clear, the Company is
aware that PLRs have been issued since October 29, 2003. The Company has not had
any communication with the Subcommittee staff, and with the imminent conclusion
of the IRS audit, the Company continues to believe that all of its synthetic
fuel tax credits have been properly claimed.

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 into 2042. At December 31, 2003 SCE&G had capitalized
approximately $8.0 million related to the application process and expects to
capitalize an additional $1.0 million in 2004. SCE&G expects the extension to be
granted in mid-2004.

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. As a condition to obtaining the NCUC's approval of SCANA's acquisition
of PSNC Energy, PSNC Energy agreed to a moratorium on general rate cases until
August 2005. General rate relief can be obtained to recover costs associated
with materially adverse governmental actions and force majeure events.

         The U. S. Congress passed the Pipeline Safety Improvement Act of 2002
(the Act), which directs the U. S. Department of Transportation (DOT) to
establish a pipeline integrity management rule for operations of natural gas
transmission pipelines that have moderate to high-density population areas
within close proximity. The Act requires DOT to set stringent regulations on
segments of transmission pipeline where leaks or ruptures could threaten people
or property. As a result, PSNC Energy must inspect and assess the physical
reliability of the approximately 500 miles of its transmission line that are
covered by the Act within the initial ten-year deadline established by the Act.
Depending on the assessment method used, PSNC Energy will be required to
reinspect these same lines every five to seven years after the initial deadline.
Total costs for compliance with the Act have not been determined.

South Carolina Pipeline Corporation

         SCPC has 2,000 miles of transmission line that are covered by the Act.
Total costs for compliance with the Act have not been determined.


<PAGE>



CRITICAL ACCOUNTING POLICIES

        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.

Utility Regulation

        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. 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. See
Note 1 of Notes to the consolidated financial statements for a description of
the Company's regulatory assets and liabilities, including those associated with
the Company's environmental assessment program.

        The Company's generation assets would be exposed to considerable
financial risks in a deregulated electric market. If market prices for electric
generation do not produce adequate revenue streams and the enabling legislation
or regulatory actions do not provide for recovery of the resulting stranded
costs, the Company could be required to write down its investment in 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, 2003 the Company's net investments in fossil/hydro and nuclear
generation assets were approximately $2,363 million and $563 million,
respectively.

Revenue Recognition and Unbilled Revenues

        Revenues related to the sale of energy are recorded when service is
rendered or when energy is delivered to customers. Because customers of 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, the Company
records estimates for unbilled revenues at the end of each reporting period.
Such unbilled revenue amounts reflect estimates of the amount of energy
delivered to 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, 2003 and 2002, accounts
receivable included unbilled revenues of $133.9 million and $107.7 million,
respectively, compared to total revenues for 2003 and 2002 of $3.42 billion and
$2.95 billion, respectively.

Provisions for Bad Debts and Allowances for Doubtful Accounts

        As of each balance sheet date, the Company evaluates the collectibility
of accounts receivable and records allowances for doubtful accounts based on
estimates of the level of expected write-offs. These estimates are based on,
among other things, comparisons of the relative age of accounts, assigned credit
ratings for commercial and industrial accounts, and consideration of actual
write-off history. The distribution segments of the Company's regulated
utilities have established write-off histories and regulated service areas that
enable the utilities to reliably estimate their respective provisions 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.


<PAGE>


Nuclear Decommissioning

        Accounting for decommissioning costs for nuclear power plants involves
significant estimates related to costs to be incurred many years in the future.
Among the factors that could change SCE&G's accounting estimates related to
decommissioning costs are changes in technology, changes in regulatory and
environmental remediation requirements, and changes in financial assumptions
such as discount rates and timing of cash flows. SCE&G expects to receive a
20-year license extension for Summer Station that will significantly impact the
eventual cost of and funding for decommissioning. 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.

        Under SCE&G's method of funding decommissioning costs, 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.

Accounting for Pensions and Other Postretirement Benefits

        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 $5.0 million recorded in 2003 reflects
the use of a 6.5% discount rate and an assumed 9.25% long-term return on plan
assets. SCANA believes that these assumptions were, and that the resulting
pension income amount was, reasonable. For purposes of comparison, using a
discount rate of 6.0% in 2003 would have lowered SCANA's pension income by
approximately $1.9 million. Had the assumed long-term return on assets been
reduced to 9.0% in 2003, SCANA's pension income would have been reduced by
approximately $1.6 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 beginning of year discount rate of 6.5% as being within a
reasonable range of interest rates for obligations rated Aa by Moody's as of
January 1, 2003. This same discount rate was also selected for determination of
other postemployment benefits (OPEB) costs discussed below.

        The following information with respect to pension assets (and returns
thereon) should also be noted:

        The Company determines the fair value of substantially all of its
pension assets utilizing market quotes rather than utilizing any calculated
values, "market related" values or other modeling techniques. In developing the
expected long-term rate of return assumptions, the Company evaluated input from
actuaries and from pension fund investment advisors, including such advisors'
review of the plan's historical 10, 16 and 25 year cumulative actual returns of
10.8%, 12.0% and 12.7%, respectively, all of 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 a target
asset allocation of 70% with equity managers and 30% with fixed income managers.
Management regularly reviews such allocations and periodically rebalances the
portfolio to the targeted allocation when considered appropriate.

        While investment performance in 2000-2002 and the recent 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 after 2008.

        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 6.5% and recorded a
net SFAS 106 cost of $17.3 million for 2003. Had the selected discount rate been
6.0%, the expense for 2003 would have been approximately $0.5 million higher.

Goodwill

        In connection with the adoption, effective January 1, 2002, of SFAS 142,
"Goodwill and Other Intangible Assets," the Company performed a valuation
analysis of its investment in SCPC (the Company's Gas Transmission segment)
using a discounted cash flow analysis and of PSNC Energy (part of the Company's
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 PSNC Energy's 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. Subsequent annual calculations required by SFAS 142 have indicated no need
for further write-downs.

Asset Retirement Obligations

        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 their acquisition, construction, development and normal
operation. Because such obligation relates solely to the Company's regulated
electric utility, adoption of SFAS 143 had no impact on results of operations;
however, as of January 1, 2003, the Company recorded an ARO of approximately
$111 million, which exceeded the previously recorded reserve for nuclear plant
decommissioning of approximately $87 million. At December 31, 2003 such ARO
totaled approximately $118 million.

        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.

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," or as described in Financial
Accounting Standards Board Interpretation 46, "Consolidation of Variable
Interest Entities." SCANA 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.

Claims and Litigation

        For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS
and the consolidated financial statements for the Company (Note 10), SCE&G (Note
10) and PSNC Energy (Note 8).

Telecommunications Investments

        The Company's basis in telecommunications investments at December 31,
2003 totaled $47.0 million for equity securities and $62.5 million for debt
securities. For a description of such investments, see Note 9 to the Company's
consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        All financial instruments held by the Company described below are held
for purposes other than trading.

        Interest rate risk - The tables below 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, 2003                                                    Expected Maturity Date
  Millions of dollars

  Liabilities                          2004      2005      2006      2007        2008     Thereafter    Total      Fair Value
  ----------------------------------- -------- --------- --------- ---------- ----------- ----------- ----------- --------------

    Long-Term Debt:
<S>            <C>                     <C>      <C>       <C>        <C>        <C>        <C>         <C>           <C>
    Fixed Rate ($)                     197.9    193.6     174.4      68.6       158.6      2,540.9     3,334.0       3,384.1
    Average Fixed Interest Rate (%)      7.53     7.39      8.50     6.96         8.12         6.27        6.63
    Variable Rate ($)                                     200.0                                           200.0        200.0
    Average  Variable  Interest Rate                        1.62                                           1.62
  (%)
    Interest Rate Swaps:
    Pay Variable/Receive Fixed ($)      57.5      3.20      3.20     28.2       118.2        126.0        336.3          6.33
    Average Pay Interest Rate (%)       5.99      4.36      4.36     4.48         3.04         3.01        3.68
    Average Receive Interest Rate       7.70      8.75      8.75     7.11         5.89         6.57        6.61
  (%)

  December 31, 2002                                                    Expected Maturity Date
  Millions of dollars

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

    Long-Term Debt:
    Fixed Rate ($)                     308.5    197.9     193.6      174.4        68.6     2,169.3     3,112.3       3,244.6
    Average Fixed Interest Rate (%)     7.27      7.53      7.39      8.50        6.96          6.73       6.98
    Variable Rate ($)                  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
  (%)
</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.

         At December 31, 2003 the Company held investments in the 13% senior
unsecured notes (due 2009) of a telecommunications company, the cost basis of
which, including accrued interest, is approximately $49.5 million. As these
notes are not actively traded, determination of their fair value is not
practicable.



         Commodity price risk - The following tables 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.
<TABLE>
<CAPTION>

As of December 31, 2003
Millions of dollars, except weighted average settlement price and strike
price

Natural Gas Derivatives:    Expected Maturity in 2004       Expected Maturity in 2005       Expected Maturity in 2006
------------------------- ------------------------------ -------------------------------- -------------------------------
------------------------- ---------- --------- --------- ----------- --------- ---------- ----------- --------- ---------
                          Settlement Contract    Fair    Settlement  Contract    Fair     Settlement  Contract    Fair
                          Price (a)   Amount    Value    Price (a)    Amount     Value    Price (a)    Amount    Value
Futures Contracts:
<S>   <C>                   <C>        <C>       <C>        <C>        <C>        <C>        <C>        <C>       <C>
  Long($)                   5.74       41.6      46.9       5.05       3.5        4.0        5.12       0.5       0.6
  Short($)                  6.09        0.7       0.7
</TABLE>

                                  Strike          Contract
                                   Price          Amount
                                   (a)
Options:
  Purchased call (long)($)         5.55           43.4

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

(a) weighted average

          The Company uses derivative instruments to hedge forward purchases and
sales of natural gas, which create market risks of different types. See Note 9
of the Company's consolidated financial statements.

          The NYMEX futures information above includes those financial positions
of Energy Marketing, SCPC and PSNC Energy. 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 and, as such, are subject to the SCPSC's annual
prudency review. The offset to the change in fair value of these derivatives is
recorded as a current asset or liability.


<PAGE>



          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 provision for the recovery of actual gas costs incurred. PSNC Energy
records transaction fees and any realized gains or losses from derivatives
acquired as part of its hedging program in deferred accounts as a regulatory
asset or liability for the over or under recovery of gas costs. In an October
2003 order, in connection with PSNC Energy's 2003 annual prudency review, the
NCUC determined that PSNC Energy's gas costs, including all hedging
transactions, were reasonable and prudently incurred during the 12-month review
period ended March 31, 2003.

          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 $50.2 million at December 31, 2003. A temporary decline in
value of ten percent would result in a $5.0 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 $5.0
million reduction in fair value and a corresponding adjustment to net income,
net of tax effect. The investment in preferred stock with significant debt
characteristics is carried at cost of $13.0 million at December 31, 2003. A
temporary decline in value of ten percent would result in a $1.3 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 $1.3 million reduction in fair value and a
corresponding adjustment to net income, net of tax effect.


<TABLE>
<CAPTION>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                                INDEX TO CONSOLIDATED FINANCIAL
                                          STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA

                                                                    Page

<S>                                                                                                 <C>
  Independent Auditors' Report................................................................      52

  Consolidated Financial Statements:

     Consolidated Balance Sheets as of December 31, 2003 and 2002.............................      53

     Consolidated Statements of Operations for the Years Ended
         December 31, 2003, 2002 and 2001 ....................................................      55

  Consolidated Statements of Cash Flows for the Years Ended December 31, 2003,
         2002 and 2001........................................................................      56

  Consolidated Statements of Capitalization as of December 31, 2003 and 2002..................      57

     Consolidated Statements of Comprehensive Income (Loss) and Changes in Common
         Equity for the Years Ended December 31, 2003, 2002 and 2001 .........................       59

     Notes to Consolidated Financial Statements...............................................       60
</TABLE>


<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, 2003 and 2002
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, 2003. 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, 2003
and 2002 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information as set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets," effective January 1, 2002.


s/Deloitte & Touche LLP
Columbia, South Carolina
February 26, 2004







<PAGE>
<TABLE>
<CAPTION>


      SCANA Corporation
     CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------------------- ------------------- ---------------------
December 31,  (Millions of dollars)                                                          2003                 2002
------------------------------------------------------------------------------------- ------------------- ---------------------
Assets
Utility Plant (Note 4):
<S>                                                                                         <C>                  <C>
    Electric                                                                                $5,558               $5,228
    Gas                                                                                       1,687               1,593
    Common                                                                                      193                 184
------------------------------------------------------------------------------------- ------------------- ---------------------
    Total                                                                                     7,438               7,005
    Accumulated depreciation and amortization                                                (2,280)             (2,151)
------------------------------------------------------------------------------------- ------------------- ---------------------
    Total                                                                                     5,158               4,854
    Construction work in progress                                                               987                 677
    Nuclear fuel, net of accumulated amortization                                                 42                  38
    Acquisition adjustments, net of accumulated amortization (Note 1)                           230                 230
------------------------------------------------------------------------------------- ------------------- ---------------------
    Utility Plant, Net                                                                        6,417               5,799
------------------------------------------------------------------------------------- ------------------- ---------------------

Nonutility Property, Net of Accumulated Depreciation                                              96                 95
Investments (Note 9)                                                                            178                 231
------------------------------------------------------------------------------------- ------------------- ---------------------
    Nonutility Property and Investments, Net                                                    274                326
------------------------------------------------------------------------------------- ------------------- ---------------------

Current Assets:
    Cash and temporary investments (Note 9)                                                     136                 374
    Receivables, net of allowance for uncollectible
       accounts of $16 and $17                                                                  503                 481
    Receivables - affiliated companies                                                            13                   8
    Inventories (at average cost):
        Fuel                                                                                    147                 166
        Materials and supplies                                                                    60                  61
        Emission allowances                                                                        6                 10
    Prepayments                                                                                  36                  40
------------------------------------------------------------------------------------- ------------------- ---------------------
    Total Current Assets                                                                        901               1,140
------------------------------------------------------------------------------------- ------------------- ---------------------

Deferred Debits:
    Environmental                                                                                20                   27
    Nuclear plant decommissioning                                                                  -                  87
    Assets held in trust, net-nuclear decommissioning                                            44                    -
    Pension asset, net  (Note 3)                                                                270                 265
    Other regulatory assets                                                                     348                 292
    Other                                                                                       175                 138
------------------------------------------------------------------------------------- ------------------- ---------------------
    Total Deferred Debits                                                                       857                  809
------------------------------------------------------------------------------------- ------------------- ---------------------
            Total                                                                           $8,449               $8,074
===================================================================================== =================== =====================

</TABLE>

<PAGE>



<TABLE>
<CAPTION>




   ------------------------------------------------------------------------- ------------------- ---------------------
   December 31,  (Millions of dollars)                                              2003                 2002
   ------------------------------------------------------------------------- ------------------- ---------------------
   Capitalization and Liabilities
   Shareholders' Investment:
<S>                         <C>                                                    <C>                  <C>
       Common equity  (Note 6)                                                     $2,306               $2,177
       Preferred stock (Not subject to purchase or sinking funds) (Note 7)             106                  106
   ------------------------------------------------------------------------- ------------------- ---------------------
           Total Shareholders' Investment                                           2,412                2,283
   Preferred Stock, net (Subject to purchase or sinking funds) (Note 7)                   9                    9
   SCE&G-Obligated Mandatorily Redeemable Preferred Securities
       of SCE&G's Subsidiary Trust, SCE&G Trust I (Note 7)                                -                       50
   Long-Term Debt, net  (Notes 4 & 9)                                               3,225                2,834
   ------------------------------------------------------------------------- ------------------- ---------------------
       Total Capitalization                                                         5,646                5,176
   ------------------------------------------------------------------------- ------------------- ---------------------

   Current Liabilities:
       Short-term borrowings  (Notes 5 & 9)                                            195                  209
       Current portion of long-term debt  (Notes 4 & 9)                                202                  413
       Accounts payable                                                                307                  354
       Accounts payable - affiliated companies                                          12                     8
       Customer deposits                                                                43                   33
       Taxes accrued                                                                    84                    78
       Interest accrued                                                                 55                    52
       Dividends declared                                                                41                   39
       Deferred income taxes, net  (Note 8)                                              4                     4
       Other                                                                            74                   86
   ------------------------------------------------------------------------- ------------------- ---------------------
       Total Current Liabilities                                                    1,017                1,276
   ------------------------------------------------------------------------- ------------------- ---------------------

   Deferred Credits:
       Deferred income taxes, net  (Note 8)                                            787                  747
       Deferred investment tax credits (Note 8)                                        117                  118
       Reserve for nuclear plant decommissioning                                          -                  87
       Asset retirement obligation - nuclear plant                                     118                    -
       Postretirement benefits  (Note 3)                                               135                  131
       Other regulatory liabilities                                                    519                 439
       Other                                                                           110                 100
   ------------------------------------------------------------------------- ------------------- ---------------------
       Total Deferred Credits                                                       1,786                1,622
   ------------------------------------------------------------------------- ------------------- ---------------------

   Commitments and Contingencies (Note 10)                                                -                   -
   ------------------------------------------------------------------------- ------------------- ---------------------

              Total                                                                $8,449               $8,074
   ========================================================================= =================== =====================

    See Notes to Consolidated Financial Statements.

</TABLE>


<PAGE>






<TABLE>
<CAPTION>

  SCANA Corporation
  CONSOLIDATED STATEMENTS OF OPERATIONS
  ------------------------------------------------------------------------ ---------------- --------------- -------------- --
  For the Years Ended December 31,                                              2003             2002           2001
  ------------------------------------------------------------------------ ---------------- --------------- -------------- --
  (Millions of Dollars, except per share amounts)

  Operating Revenues (Note 2):
<S>                                                                            <C>              <C>             <C>
      Electric                                                                 $1,466           $1,380          $1,369
      Gas - regulated                                                            1,086              878           1,015
      Gas - nonregulated                                                           864              696           1,067
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
          Total Operating Revenues                                               3,416           2,954            3,451
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Operating Expenses:
      Fuel used in electric generation                                             334             330              283
      Purchased power                                                               64               42             138
      Gas purchased for resale                                                   1,532           1,199            1,681
      Other operation and maintenance                                              558             522              482
      Depreciation and amortization                                                238              220             224
      Other taxes                                                                  139              127             115
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
          Total Operating Expenses                                               2,865           2,440            2,923
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Operating Income                                                                 551              514             528
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Other Income (Expense):
      Other income, including allowance for equity funds
         used during construction of $19, $23 and $15                                67              71              55
      Gain on sale of investments and assets (Note 9)                                61              40             557
      Impairment of investments (Note 9)                                            (53)          (291)             (62)
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
          Total Other Income (Expense)                                              75            (180)             550
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Income Before Interest Charges, Income Taxes, Preferred Stock
     Dividends and Cumulative Effect of Accounting Change                          626             334            1,078
  Interest Charges, Net of Allowance for Borrowed Funds
    Used During Construction of $11, $12 and $11                                   200             199              223
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Income Before Income Taxes, Preferred Stock Dividends
     and Cumulative Effect of Accounting Change                                    426             135              855
  Income Taxes (Note 8)                                                            135               36             305
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Income Before Preferred Stock Dividends and Cumulative
      Effect of Accounting Change                                                  291               99             550
  Dividend Requirement of SCE&G - Obligated Mandatorily
      Redeemable Preferred Securities                                                 2               4                4
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Income Before Cash Dividends on Preferred Stock of Subsidiary
     and Cumulative Effect of Accounting Change                                    289               95             546
  Cash Dividends on Preferred Stock of Subsidiary (At stated rates)                   7               7               7
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
  Income Before Cumulative Effect of Accounting Change                             282               88            539
  Cumulative Effect of Accounting Change, net of taxes  (Note 1G)                     -           (230)               -
  ------------------------------------------------------------------------ ---------------- --------------- ----------------

  Net Income (Loss)                                                               $282           $(142)           $539
  ======================================================================== ================ =============== ================

  Basic and Diluted Earnings (Loss) Per Share of Common Stock:
     Before Cumulative Effect of Accounting Change                               $2.54           $0.83           $5.15
     Cumulative Effect of Accounting Change, net of taxes  (Note 1G)                  -           (2.17)              -
  ------------------------------------------------------------------------ ---------------- --------------- ----------------
     Basic and Diluted Earnings (Loss) Per Share                                $2.54           $(1.34)          $5.15
  ======================================================================== ================ =============== ================
  Weighted Average Common Shares Outstanding (millions)                         110.8            106.0           104.7

  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)                                           2003         2002          2001
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Operating Activities:
<S>                                                                                              <C>           <C>          <C>
Net income (loss)                                                                                $282          $(142)       $539
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
    Cumulative effect of accounting change, net of taxes                                              -         230              -
    Depreciation and amortization                                                                  249          233           236
    Amortization of nuclear fuel                                                                    21           20            16
    Gain on sale of assets and investments                                                         (61)         (40)         (557)
    Impairment of investments                                                                       53          291            62
    Hedging activities                                                                               4           42           (65)
    Allowance for funds used during construction                                                   (30)         (35)          (26)
    Over (under) collection, fuel adjustment clauses                                                23          (15)           20
    Changes in certain assets and liabilities:
         (Increase) decrease in receivables                                                        (27)         (64)          262
         (Increase) decrease in inventories                                                         24            (1)         (53)
         (Increase) decrease in prepayments                                                           4         (19)          (18)
         (Increase) decrease in pension asset                                                        (5)        (26)          (43)
         (Increase) decrease in other regulatory assets                                             (38)           3            (6)
         Increase (decrease) in deferred income taxes, net                                           38        (185)          189
         Increase (decrease) in other regulatory liabilities                                        49           39            22
         Increase (decrease) in postretirement benefits obligations                                4               9             9
         Increase (decrease) in accounts payable                                                   (43)          88         (119)
         Increase (decrease) in taxes accrued                                                         6          (4)           28
         Increase (decrease) in interest accrued                                                      3            7             3
    Changes in other assets                                                                        (33)            8             7
    Changes in other liabilities                                                                    37           52            (13)
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Provided From Operating Activities                                                        560          491           493
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Investing Activities:
      Utility property additions and construction expenditures, net of AFC                        (738)        (675)         (523)
      Proceeds on sale of investments and assets                                                    74          568            28
      Increase in nonutility property                                                              (12)         (19)          (25)
      Investments in affiliates                                                                     (17)        (62)          (46)
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Used For Investing Activities                                                            (693)        (188)         (566)
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash Flows From Financing Activities:
    Proceeds:
        Issuance of common stock                                                                      6         149             -
        Issuance of First Mortgage Bonds                                                           743          295           149
        Issuance of Industrial Revenue Bonds                                                          -          87              -
        Issuance of Pollution Control Bonds                                                         36             -             -
        Issuance of notes and loans                                                                199          497           648
        Swap settlement                                                                              -           29              6
    Repayments:
        Mortgage bonds                                                                            (350)        (104)             -
        Notes and loans                                                                           (434)        (915)         (317)
        Pollution Control Facilities Revenue Bonds                                                 (47)         (62)             -
        Payments of deferred financing costs                                                       (25)            -             -
        Retirement of preferred stock and trust preferred securities                               (50)           (1)            -
        Repurchase of common stock                                                                 (11)            -             -
    Dividends and distributions:
        Common stock                                                                              (151)        (133)         (123)
        Preferred stock                                                                              (7)          (7)           (7)
    Short-term borrowings, net                                                                     (14)          44          (233)
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net Cash Provided From (Used For) Financing Activities                                            (105)        (121)          123
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Net (Decrease) Increase in Cash and Temporary Investments                                         (238)         182             50
Cash and Temporary Investments, January 1                                                          374          192           142
--------------------------------------------------------------------------------------------- ------------ ------------ ------------
Cash and Temporary Investments, December 31                                                      $136         $374          $192
============================================================================================= ============ ============ ============
Supplemental Cash Flow Information:
Cash paid for   - Interest (net of capitalized interest of  $11, $12 and $6)                     $197         $192          $219
                         - Income taxes                                                             77          190            71
Noncash Investing and Financing Activities:
   Unrealized gain (loss) on securities available for sale, net of tax                                2          87         (226)
   Columbia Franchise Agreement                                                                       -          30             -
See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>










SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------- ------------- ---- -------------
December 31, (Millions of dollars)                                                              2003               2002
------------------------------------------------------------------------------------------- ------------- ---- -------------

Common Equity (Note 6):
  Common stock, without par value, authorized 150,000,000 shares; issued and
<S>              <C>                   <C>      <C>            <C>                             <C>                <C>
    outstanding, 110,735,859 shares in 2003 and 110,831,307 in 2002                            $1,187             $1,192
  Accumulated other comprehensive income                                                             6                   1
  Retained earnings                                                                             1,113                984
------------------------------------------------------------------------------------------- ------------- ---- -------------
Total Common Equity                                                                             2,306              2,177
------------------------------------------------------------------------------------------- ------------- ---- -------------
Preferred Stock (Notes 7 and 9):

        $100 Par Value - Authorized 1,000,000 shares; available for issuance 0
          shares $50 Par Value - Authorized 618,804 shares; available for
          issuance 300,000 shares
       $25 Par Value - Authorized and available for issuance 2,000,000 shares.



  SCE&G Cumulative Preferred Stock (Not subject to purchase or sinking funds)

                                                     Shares
                                     Outstanding
                           Series           2003     2002           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)                                  106                106
------------------------------------------------------------------------------------------- -------------- --- -------------

  SCE&G Cumulative Preferred Stock (Subject to purchase and sinking funds), $50 par

                                        Shares Outstanding
         Series                             2003    2002              Redemption Price
         ------                             ----    ----              ----------------
  4.50% & 4.60% (A)                       17,034    18,849                 $51.00                    1                1
  4.60% (B)                               50,637    51,000                  50.50                    3                3
  5.125%                                  64,000    65,000                  51.00                    3                3
  6.00%                                   61,924    65,124                  50.50                    3                3
                                        --------  - ------
  Total                          193,595   199,973
                                 =======   =======

------------------------------------------------------------------------------------------- -------------- ---- ------------
Total Preferred Stock  (Subject to purchase or sinking funds)                                      10                10
Less:  Current portion, including sinking fund requirements                                        (1)               (1)
------------------------------------------------------------------------------------------- -------------- ---- ------------
Total Preferred Stock, Net (Subject to purchase or sinking funds)                                   9                 9
------------------------------------------------------------------------------------------- -------------- ---- ------------

SCE&G-Obligated Mandatorily Redeemable Preferred Securities of SCE&G's
   Subsidiary Trust, SCE&G Trust I (Note 7)                                                         -                50
------------------------------------------------------------------------------------------- -------------- ---- ------------
</TABLE>



<PAGE>


<TABLE>
<CAPTION>



--------------------------------------------------------------------------- ---------- ----------- --- --------------
December 31,  (Millions of dollars)                                                          2003               2002
--------------------------------------------------------------------------- ---------- ----------- --- --------------
Long-Term Debt  (Notes 4 & 9)

SCANA Corporation:                        Series        Year of Maturity
<S>                                       <C>                 <C>                                                <C>
   Medium-Term Notes:                     6.51%               2003                              -                $20
                                          6.05%               2003                              -                 60
                                          6.25%               2003                              -                 75
                                          2.215%(1)           2003                              -                100
                                          7.44%(3)            2004                            $50                 50
                                          1.788%(1)           2004                              -                150
                                          1.62%(2)            2006                            200                  -
                                          6.90%(3)            2007                             25                 25
                                          5.81%(3)            2008                            115                115
                                          6.875%              2011                            300                300
                                          6.25%(3)            2012                            250                250
   Fair value of interest rate swaps                                                           36                 40

South Carolina Electric & Gas Company:    Series        Year of Maturity
   First Mortgage Bonds:                  6 1/4%              2003                              -                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
                                          5.25%               2018                            250                  -
                                          7 1/2%              2023                              -                150
                                          7 5/8%              2023                              -                100
                                          7 5/8%              2025                            100                100
                                          6.625%              2032                            300                300
                                          5.30%               2033                            300                  -
                                          5.80%               2033                            200                  -
   First and Refunding Mortgage Bonds     9%                  2006                            131                131

   Pollution Control Facilities Revenue Bonds:
      Orangeburg County Series 1994, due 2024 (5.70%)                                          30                 30
      Other                                                                                     -                 11
   Industrial Revenue Bonds, due 2012-2032 (4.2%-5.5%)                                         90                 90
   Franchise Agreement                                                                         15                 17
South Carolina Generating Company, Inc.:
   Berkeley County Pollution Control Facilities Revenue
         Bonds, due 2014 (4.875%)(4)                                                           36                 36
   Note, 7.78%, due 2011                                                                       34                 38
Public Service Company of North Carolina, Incorporated:
                                          Series        Year of Maturity
    Senior Debentures:                    10%(3)              2004                              4                  9
                                          8.75%(3)            2012                             29                 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                                                            2                  3
South Carolina Pipeline Corporation Notes, 6.72%, due 2013                                     13                 14
Other                                                                                          37                  5
--------------------------------------------------------------------------- ---------- ----------- --- --------------
Total Long-Term Debt                                                                        3,447              3,251
Less  -  Current maturities, including sinking fund requirements                            (202)              (413)
         -  Unamortized discount                                                             (20)                (4)
--------------------------------------------------------------------------- ---------- ----------- --- --------------
Total Long-Term Debt, Net                                                                   3,225              2,834
--------------------------------------------------------------------------- ---------- ----------- --- --------------
Total Capitalization                                                                       $5,646             $5,176
=========================================================================== ========== =========== === ==============

(1)  Rate at repayment
(2) Current rate, based on three-month LIBOR + 45 basis points reset quarterly
(3) Fixed rate debt hedged by variable interest rate swap (4) Rate when
refinanced, prior year rate was 6.50%

See Notes to Consolidated Financial Statements.

</TABLE>

<PAGE>

<TABLE>
<CAPTION>


SCANA Corporation
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND CHANGES IN COMMON EQUITY

------------------------------------------------ ------------------------- ------------------------- ---------------------------
For the years Ended December 31,                           2003                      2002                       2001
------------------------------------------------ ------------------------- ------------------------- ---------------------------
(Millions of Dollars)
                                                  Common    Comprehensive   Common    Comprehensive    Common    Comprehensive
                                                  Equity       Income       Equity        Loss         Equity        Income
Retained Earnings:

<S>                  <C>                             <C>                    <C>                          <C>
  Balance at January 1                               $984                   $1,264                       $850
    Net Income (loss)                                 282       $282           (142)        $(142)         539        $539
    Dividends declared on common stock               (153)                     (138)                     (125)
                                                 ---------                 ---------                 ---------

  Balance at December 31                            1,113                       984                      1,264
                                                 -- -----                  --------                  --- -----

Accumulated other comprehensive income (loss):

  Balance at January 1                                                         (113)                      139
                                                     1
     Unrealized gains (losses) on securities,
net of
        taxes ($1, $47 and $(121) in 2003,
2002,
    and 2001, respectively)                                          2           87        87            (226)        (226)
                                                     2
     Cumulative effect of change in accounting
        for hedging activities, net of taxes                         -            -          -              23          23
($12 in 2001)                                        -
     Unrealized gains (loss) on hedging
activities,
        net of taxes ($2, $15 and $(26) in
2003, 2002
        and 2001, respectively)                                      3           27        27              (49)        (49)
                                                 ---------  ------   -     --------        --          --------  ---   ----
                                                     3

     Comprehensive income (loss)                                $287                         $(28)                    $287
                                                                ====                         =====                    ====

  Balance at December 31                                                           1                     (113)
                                                 ---------                 ---------                   -------
                                                     6

Common Stock:

Balance at January 1                                1,192                    1,043                      1,043
     Shares issued                                                             149                            -
                                                     6
     Shares repurchased                                                            -                          -
                                                   (11)

Balance at December 31                              1,187                    1,192                      1,043
                                                 -- -----                  - -----                   -- -----

Total Common Equity                               $2,306                    $2,177                     $2,194
                                                  ======                    ======                     ======




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

         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 predominantly in the generation and sale
of electricity to wholesale and retail customers in South Carolina and in the
purchase, sale and transportation of natural gas to wholesale and retail
customers in South Carolina, North Carolina and Georgia. The Company 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 one other wholly
owned subsidiary in liquidation.

Regulated businesses                             Nonregulated businesses
South Carolina Electric & Gas Company (SCE&G)    SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc. (Fuel Company) SCANA Communications, Inc.(SCI)
South Carolina Generating Company, Inc. (GENCO)  ServiceCare, Inc.
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, which requires
cost-based rate-regulated utilities to recognize in their financial statements
certain revenues and expenses in different time periods than do enterprises that
are not rate-regulated. As a result, the Company has recorded as of December 31,
2003, approximately $368 million and $519 million of regulatory assets
(including environmental) and liabilities, respectively, as shown below.

<TABLE>
<CAPTION>
                                                                                             December 31,
Millions of dollars                                                                      2003            2002
----------------------------------------------------------------------------------- --------------- ---------------
----------------------------------------------------------------------------------- --------------- ---------------
<S>                                                                                      <C>              <C>
Accumulated deferred income taxes, net                                                   $110             $95
Under-collections - electric fuel and gas cost adjustment clauses, net                      38              61
Deferred environmental remediation costs                                                   20               27
Asset retirement obligation - nuclear decommissioning                                      48                -
Deferred non-conventional fuel tax benefits, net                                           (67)            (40)
Storm damage reserve                                                                       (37)            (32)
Franchise agreements                                                                        62              65
Non-legal asset retirement obligations                                                   (346)            (325)
Other                                                                                       21              29
----------------------------------------------------------------------------------- --------------- ---------------
----------------------------------------------------------------------------------- --------------- ---------------
Total                                                                                   $(151)          $(120)
=================================================================================== =============== ===============
</TABLE>

         Accumulated deferred income tax liabilities arising from utility
operations that have not been included in customer rates are recorded as a
regulatory asset. Accumulated deferred income tax assets arising from deferred
investment tax credits are recorded as a regulatory liability.


<PAGE>




         Under-collections - fuel adjustment clauses, net represent amounts
under-collected from customers pursuant to the fuel adjustment clause (electric
customers) or gas cost adjustment clause (gas customers) as approved by the
Public Service Commission of South Carolina (SCPSC) 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 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. Such costs, totaling approximately $10.9 million,
are expected to be fully recovered by the end of 2009. A portion of the costs
incurred at sites owned by PSNC Energy is also being recovered through rates,
and management believes the remaining costs of approximately $7.0 million will
be recoverable. Amounts incurred and deferred to date that are not currently
being recovered through gas rates at PSNC Energy are approximately $2.2 million.
(See Note 2).

         Asset retirement obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation to decommission and
dismantle V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143,
"Accounting for Asset Retirement Obligations." (See Note 1N).

         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 SCE&G's two partnerships involved in converting coal
to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated
from non-conventional fuel produced by the partnerships and consumed by SCE&G
and ultimately passed through to SCE&G, net of partnership losses and other
expenses, 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 period of
approximately ten years. The accumulated storm damage reserve can be applied to
offset actual incremental 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. These amounts are not earning a return, but are being
amortized through cost of service over approximately 15 years.

         Non-legal asset retirement obligations represent net collections
through depreciation rates of estimated costs to be incurred for the future
retirement of assets for which no legal retirement obligation exists. The SCPSC
and the NCUC (collectively, state commissions) have reviewed and approved
through specific orders most of the items shown as regulatory assets. Other
items represent costs which are not yet approved for recovery by a state
commission. In recording these costs as regulatory assets, management believes
the costs will be allowable under existing rate-making concepts that are
embodied in rate orders received by the Company. However, ultimate recovery is
subject to state commission approval. In the future, as a result of deregulation
or other changes in the regulatory environment, the Company may no longer meet
the criteria for continued application of SFAS 71 and could be required to write
off its regulatory assets and liabilities. Such an event could have a material
adverse effect on the Company's results of operations, liquidity or financial
position in the period the write-off would be recorded.

C.  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 to accumulated depreciation.
The costs of repairs, replacements and renewals of items of property determined
to be less than a unit of property are charged to maintenance expense.

         SCE&G, operator of the 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 $1,002.8 million and $962.4 million as of
December 31, 2003 and 2002, respectively (including amounts related to ARO).
Accumulated depreciation associated with SCE&G's share of Summer Station was
approximately $449.5 million and $417.9 million as of December 31, 2003 and
2002, respectively (including amounts related to ARO). SCE&G's share of the
direct expenses associated with operating Summer Station is included in "Other
operation and maintenance" expenses and totaled approximately $74.7 million for
the year ended December 31, 2003.

         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. SCE&G accrued approximately
$0.5 million per month from January 2001 through June 2002 for the outage period
ended June 2002, and approximately $0.6 million per month from July 2002 through
December 2003 for the outage period ended December 2003. Total outage costs for
the fall 2003 outage were approximately $20.6 million, of which SCE&G was
responsible for approximately $13.9 million.

E. Allowance for Funds Used During Construction (AFC)

         AFC is a noncash item that reflects the period cost of capital devoted
to plant under construction. This accounting practice results in the inclusion
of, as a component of construction cost, the costs of debt and equity capital
dedicated to construction investment. AFC is included in rate base investment
and depreciated as a component of plant cost in establishing rates for utility
services. The Company's regulated subsidiaries calculated AFC using composite
rates of 8.1%, 8.3% and 8.8% for 2003, 2002 and 2001, 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. Unbilled revenues totaled
approximately $133.9 million and $107.7 million as of December 31, 2003 and
2002, 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 $26.7 million and $25.3 million at
December 31, 2003 and 2002, respectively, which amounts are included in other
regulatory assets.

         Customers subject to the gas cost adjustment clause are billed based on
a fixed cost of gas determined by the state commission during annual gas cost
recovery hearings. Any difference between actual gas costs and amounts contained
in rates is deferred and included when establishing gas costs during the next
annual gas cost recovery hearing. At December 31, 2003 and 2002 SCE&G had
undercollected through the gas cost recovery procedure approximately $11.9
million and $24.6 million, respectively, which amounts are also included in
other regulatory assets. At December 31, 2003 PSNC Energy had overcollected
through the gas cost recovery procedure approximately $1.0 million, which is
included in other regulatory liabilities. At December 31, 2002 PSNC Energy had
undercollected $10.6 million which is included in other regulatory assets.

         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.



<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
as follows:


                            2003           2002            2001
-------------------------------------- -------------- ---------------
SCE&G                      3.02%           2.93%          2.98%
GENCO                      2.66%           2.66%          2.71%
SCPC                       2.13%           2.14%          2.60%
PSNC Energy                4.05%           4.29%          4.06%
Aggregate of Above         3.10%           3.06%          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. See Note
1H.

       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)                  2003         2002        2001
                                                                   ----         ----        ----

<S>                                                                <C>         <C>           <C>
  Net Income (Loss) as Reported                                    $282        $(142)        $539
  Amortization of Acquisition Adjustment                                -            -         14
                                                                ------- -    ------  -    ---- --
  Net Income (Loss) as Adjusted                                    $282        $(142)       $553
                                                                   ====        ======       ====

  Basic and Diluted Earnings (Loss) Per Share As Reported          $2.54       $(1.34)      $5.15
  Amortization of Acquisition Adjustment                                -            -        .14
                                                                ------- -    ------- -    --- ---
  Basic and Diluted Earnings (Loss) Per Share As Adjusted          $2.54       $(1.34)      $5.29

                                                                   =====       =======      =====
</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 or
$2.17 per share. The resulting impairment charge is reflected on the statement
of operations as the cumulative effect of an accounting change. SFAS 142
requires that an impairment evaluation be performed annually and at the same
time each year. The Company performed its annual evaluation as of January 1,
2003 and no further impairment was indicated.

H.   Nuclear Decommissioning

       SCE&G's share of estimated site-specific nuclear decommissioning costs
for Summer Station, including the cost of decommissioning plant components not
subject to radioactive contamination, totals approximately $357.3 million,
stated in 1999 dollars, based on a decommissioning study completed in 2000.
Santee Cooper is responsible for decommissioning costs related to its one-third
ownership interest in the station. The cost estimate is based on a
decommissioning methodology acceptable to the Nuclear Regulatory Commission
(NRC) under which the site would be maintained over a period of approximately 60
years in such a manner as to allow for subsequent decontamination that permits
release for unrestricted use. SCE&G records its liability for decommissioning
cost in deferred credits.

       Under SCE&G's method of funding decommissioning costs, funds collected
through rates ($3.2 million in each of 2003, 2002 and 2001) 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.

       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 $1.5 million and $2.0
million at December 31, 2003 and 2002, 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
is included in other regulatory assets.

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 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 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 are amortized with recovery provided through rates. Deferred
amounts for SCE&G, net of amounts previously recovered through rates and
insurance settlements, totaled $10.9 million and $17.9 million at December 31,
2003 and 2002, respectively. Deferred amounts for PSNC Energy totaled
approximately $7.0 million and $7.8 million at December 31, 2003 and 2002,
respectively. The deferral includes the estimated costs associated with the
matters discussed in Note 10C.


<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, repurchase agreements, treasury bills and notes.

M.  Commodity Derivatives

        The Company records derivatives contracts at their fair value in
accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended, and adjusts fair value each reporting period. The
Company 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. Substantially all of the Company's derivatives contracts do not extend
beyond two years. (See Note 9). 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 current asset or liability. PSNC Energy's
tariffs include a provision for the recovery of actual gas costs incurred. PSNC
Energy records transactions fees and any realized gains or losses from
derivatives acquired as part of its hedging program in deferred accounts as a
regulatory asset or liability for the over or under recovery of gas costs.

 N.   New Accounting Standards

        The Company adopted SFAS 143 effective January 1, 2003. SFAS 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. As of December 31, 2002, prior
to the adoption of SFAS 143, the Company carried deferred debits and deferred
credits (each totaling approximately $87 million) related to the decommissioning
and dismantling of Summer Station and the funding thereof. Effective January 1,
2003, in connection with the initial measurement of the ARO, the amounts
reflected within these regulatory assets and liabilities were recharacterized.

        The following table presents such recharacterized amounts related to the
decommissioning obligation and the funding thereof as recorded in the
Consolidated Balance Sheet as of December 31, 2003, and the proforma amounts
that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been
adopted at the beginning of 2001.
<TABLE>
<CAPTION>

                                                                   December 31,      December 31,    December 31,
Millions of dollars                                                    2003              2002            2001
-------------------
                                                                      Actual           Proforma        Proforma
Assets:
<S>                                                                      <C>              <C>             <C>
Within electric plant                                                    $40              $40             $40
Within accumulated depreciation                                          (14)             (13)             (12)
Assets held in trust (net) - nuclear decommissioning                      44               39               35
Within other regulatory assets                                            48               45               42
                                                                 ------------------ --------------- ----------------
                                                                 ------------------ --------------- ----------------
     Total                                                             $118              $111            $105
                                                                 ================== =============== ================
                                                                 ================== =============== ================

Liabilities:
 Asset retirement obligation - nuclear plant decommissioning           $118              $111            $105
                                                                 ================== =============== ================
</TABLE>

        Proforma net income (loss) and earnings (loss) per share for periods
prior to the adoption of SFAS 143 would not differ from amounts actually
recorded during these periods.


<PAGE>


        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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. 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. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.

        The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.

     The Company adopted the disclosure  provisions of SFAS 148, "Accounting for
Stock-Based  Compensation - Transition  and  Disclosure,"  effective  January 1,
2003.  SFAS  148  requires  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. There was no
impact on the Company's results of operations,  cash flows or financial position
from the initial adoption of SFAS 148.

        SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities".
SFAS 149 is effective for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 149.

        SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. SFAS
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise was effective at the beginning of the first interim
period beginning after June 15, 2003. There was no impact on the Company's
results of operations, cash flows or financial position from the initial
adoption of SFAS 150.

        The Company adopted SFAS 132 (Revised 2003), Employers' Disclosure about
Pension and Other Postretirement Benefits," which is effective for financial
statements issued for fiscal years ending December 15, 2003. This statement
increased existing disclosure requirements by requiring more details about
assets, obligations, cash flows and net periodic benefit cost of defined benefit
pension plans and other defined benefit postretirement plans. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of this statement.


<PAGE>



O.  Equity Compensation Plan

        Under the SCANA Corporation Long-Term Equity Compensation Plan (the
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 SFAS 148 "Accounting
for Stock-Based Compensation - Transition and Disclosure."

        All options have been granted with exercise prices equal to the fair
market value of the Company's stock on the respective grant dates since the
Plan's inception; therefore, 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, pro forma net income (loss) and earnings (loss) per share would have been
as presented below:
<TABLE>
<CAPTION>

                                                                   2003             2002             2001
                                                                   ----             ----             ----
<S>                                                               <C>             <C>               <C>
Net income (loss) - as reported  (millions)                       $282.0          $(141.7)          $539.3
Net income (loss) - pro forma (millions)                            280.3          (143.3)            538.5
Basic and diluted earnings (loss) per share - as reported            2.54           (1.34)              5.15
Basic and diluted earnings (loss) per share - pro forma              2.52           (1.35)              5.14
</TABLE>

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.  Affiliated Transactions

        SCE&G holds two equity-method investments in partnerships involved in
converting coal to non-conventional fuel. SCE&G had recorded as receivables from
these affiliated companies approximately $13.4 million and $8.5 million at
December 31, 2003 and 2002, respectively. SCE&G had recorded as payables to
these affiliated companies approximately $12.2 million and $8.0 million at
December 31, 2003 and 2002, respectively.

R.  Reclassifications

        Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2003.

S.  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.


<PAGE>



2. RATE AND OTHER REGULATORY MATTERS

        South Carolina Electric & Gas Company (SCE&G)

        Electric

        In January 2003 the SCPSC granted SCE&G a composite increase in retail
electric rates of approximately 5.8% 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 its
order, the SCPSC extended through 2005 its approval of the accelerated capital
recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the
level of revenues and operating expenses, 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 additional approval of the SCPSC. Any unused portion of the $36 million
in any given year may be carried forward for possible use in the following year.

        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 was effective for service rendered on and
after February 1, 2003. In April 2003 the SCPSC issued an order approving
SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per
KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's
purchasing practices and recognized the efficiency of SCE&G's electric
generating plants; however, it deferred action on the recovery of certain
purchased power costs pending the resolution of the appeal of the SCPSC's May
2002 order discussed below.

        In December 2002 the SCPSC approved 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 approved 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 reflected 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. The Consumer Advocate of South Carolina
appealed to the South Carolina Circuit Court (Circuit Court) the portion of the
SCPSC's order related to the recovery of certain purchased power costs. The
appeal is still pending.

         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, 2003 and 2002 was as follows:

Rate Per Therm  Effective Date           Rate Per Therm   Effective Date

    $.728       January-February 2003         $.596       January-October  2002
    $.928       March-October 2003            $.728       November-December 2002
    $.877       November-December 2003

        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 2003, as a result of the annual
review, the SCPSC approved SCE&G's request to reduce the billing surcharge from
3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the
recovery, prior to the end of the year 2009, of the balance remaining at
December 31, 2003 of $10.9 million.

        Public Service Company of North Carolina, Incorporated (PSNC Energy)

        PSNC Energy's rates are established using a benchmark cost of gas
approved by the NCUC, which may be modified periodically to reflect changes in
the market price of natural gas. PSNC Energy revises its tariffs with the NCUC
as necessary to track these changes and accounts for any over- or
under-collections of the delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing
practices annually.

         PSNC Energy's benchmark cost of gas in effect during the years ended
December 2003 and 2002 was as follows:

 Rate Per Therm  Effective Date         Rate Per Therm    Effective Date

     $.460       January-February 2003      $.300         January 2002
     $.595       March 2003                 $.215         February-June 2002
     $.725       April-November 2003        $.350         July-October 2002
     $.600       December 2003              $.410         November-December 2002

        On October 13, 2003 in connection with PSNC Energy's 2003 Annual
Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all
hedging transactions, were reasonable and prudently incurred during the 12-month
review period ended March 31, 2003. The NCUC also authorized new rate decrements
to refund overcollections of certain gas costs included in PSNC Energy's
deferred accounts, effective November 1, 2003.

        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 in 2002, and the Swain County
portion is expected to be completed in the spring of 2004. Through December 31,
2003 approximately $27.4 million had been spent on this project.

        In December 1999 the NCUC issued an order approving the Company'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 order dated August 5, 2003,
the SCPSC found that for the period April 2002 through December 2002 SCPC's gas
purchasing policies and practices were prudent and SCPC properly adhered to the
gas cost recovery provisions of its gas tariff.

3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

Pension and Other Postretirement 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.


<PAGE>



        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 credited
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.

        In addition to pension benefits, the Company provides certain unfunded
postretirement health care and life insurance benefits to active and retired
employees. Retirees share in a portion of their medical care cost. The Company
provides life insurance benefits to retirees at no charge. The costs of
postretirement benefits other than pensions are accrued during the years the
employees render the services necessary to be eligible for the applicable
benefits.

        The measurement date used to determine pension and other postretirement
benefit obligations is December 31. Information regarding the benefit
obligations and the funding thereof is presented below.

Changes in Benefit Obligation

        Data related to the changes in the projected benefit obligation for
retirement benefits and the accumulated benefit obligation for other
postretirement benefits are presented below.
<TABLE>
<CAPTION>

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

Millions of dollars                                2003        2002                 2003               2002
                                                   ----        ----                 ----               ----

<S>                         <C>                  <C>         <C>                  <C>                <C>
Benefit obligation, January 1                    $595.6      $530.8               $183.4             $166.7
Service cost                                        9.5         9.1                  2.7                3.1
Interest cost                                      36.7        39.8                 11.4               12.4
Plan participants' contributions                      -           -                  0.8                0.9
Actuarial loss                                      7.6        50.6                  4.3               10.8
Benefits paid                                    (29.5)      (34.7)               (14.2)             (10.5)
                                                 ------   -- -----                ------  ---        -----
Benefit obligation,  December 31                 $619.9      $595.6               $188.4             $183.4

                                                 ======      ======               ======             ======
</TABLE>

        The accumulated benefit obligation for retirement benefits at the end of
2003 and 2002 was $589.8 million and $570.0 million, respectively. These
accumulated retirement benefit obligations differ from the projected retirement
benefit obligations above in that they reflect no assumptions about future
compensation levels.

        Significant assumptions used to determine the above benefit obligations
are as follows:

<TABLE>
<CAPTION>
                                                                                        2003         2002
<S>                                                                                    <C>          <C>
  Annual discount rate used to determine benefit obligations                           6.00%        6.50%
  Assumed annual rate of future salary increases for projected benefit obligation      4.00%        4.00%
</TABLE>

        A 9.5% annual rate of increase in the per capita cost of covered health
care benefits was assumed for 2004. The rate was assumed to decrease gradually
to 5.0% for 2011 and remain at that level thereafter. The effects of a one
percentage point increase or decrease on accumulated other postretirement
benefit obligation for health care benefits are as follows:

                                                   1%            1%
  Millions of dollars                           Increase      Decrease
                                             ------------------------------

  Effect on postretirement benefit obligation     $0.9         $(1.1)



<PAGE>



        The Medicare Prescription Drug, Improvement and Modernization Act of
2003 (the Act) was signed December 8, 2003 to make additional voluntary
prescription drug benefits available through Medicare. SCANA has elected not to
recognize the effects of the Act in these financial statements. The Company will
be evaluating the implications of the Act during 2004 and will recognize
expected financial effects as prescribed by accounting standards in effect for
subsequent reporting periods.

Changes in Plan Assets

                                                   Retirement Benefits
                                            -----------------------------------
Millions of dollars                          2003               2002
                                             ----               ----

Fair value of plan assets, January 1        $666.9             $831.6
Actual return on plan assets                 150.3              (130.0)
Benefits paid                                 (29.5)             (34.7)
                                              ------             -----
Fair value of plan assets, December 31      $787.7             $666.9
                                            ======             ======

        At the end of 2003 and 2002, the fair value of plan assets for the
pension plan exceeded both the benefit obligation and the accumulated benefit
obligation discussed above. Since the accumulated benefit obligation is less
than the fair value of plan assets, there is no adjustment to other
comprehensive income.
<TABLE>
<CAPTION>

Funded Status of Plans

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

Millions of dollars                                                    2003      2002           2003           2002
                                                                       ----      ----           ----           ----

<S>                     <C>                                          <C>        <C>         <C>            <C>
Funded status, December 31                                           $167.8     $71.3       $(188.4)       $(183.4)
Unrecognized actuarial (gain) loss                                     23.1     107.5           45.0           42.2
Unrecognized prior service cost                                        76.8      83.1            2.9            3.9
Unrecognized net transition obligation                                  2.3       3.1            5.9            6.6
                                                                        ---  --------            ---  ------    ---
Net asset (liability) recognized in consolidated balance sheet       $270.0    $265.0       $(134.6)       $(130.7)
                                                                     ======    ======       ========       ========
</TABLE>

        In connection with the joint ownership of Summer Station, as of December
31, 2003 and 2002 the Company recorded within deferred credits a $9.3 million
and $9.1 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, 2003 and 2002, the Company
also recorded a $6.5 million and $6.4 million receivable, respectively, from
Santee Cooper, representing an estimate of its portion of the unfunded net
postretirement benefit obligation.

Expected Cash Flows

        The total benefits expected to be paid from the pension plan or from the
Company's assets for the pension and other postretirement benefits plans,
respectively, are as follows:

Expected Benefit Payments
Millions of dol Pension Benefits         Other Postretirement Benefits*
--------------------------------------- ---------------------------------
--------------------------------------- ---------------------------------
2004                  $39.2                          $13.4
2005                   41.0                            13.7
2006                   42.8                            14.0
2007                   43.3                            14.3
2008                   48.0                            14.5
2009 - 2013           266.0                            75.2
* Net of participant contributions


<PAGE>



Net Periodic Cost

        As allowed by SFAS 87 and SFAS 106, 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 (Income)

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

Millions of dollars                             2003        2002                            2003      2002       2001
                                                ----        ----                            ----      ----       ----
                                                                       2001

<S>                                             <C>         <C>        <C>                  <C>       <C>        <C>
Service cost                                    $9.5        $9.0       $7.9                 $2.7      $3.1       $3.0
Interest cost                                   36.7        39.8       38.5                 11.4      12.4       12.1
Expected return on assets                     (59.9)      (77.6)     (83.5)                  n/a       n/a        n/a
Prior service cost amortization                  6.3         6.3        5.8                  0.9       0.9        0.9
Actuarial (gain) loss                            1.6       (4.1)     (12.8)                  1.5       1.1        0.7
Transition amount amortization                   0.8         0.8        0.8                  0.8       0.8        0.8
                                                 ---  ----   ---  ----  ---                  ---  ---- ---  ----- ---
Net periodic benefit (income) cost            $(5.0)     $(25.8)    $(43.3)                $17.3     $18.3      $17.5
                                              ======     =======    ======                 =====     =====      =====

Significant Assumptions Used in Determining Net Periodic Cost

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

                                                2003        2002       2001                 2003       2002      2001
                                                ----        ----       ----                 ----       ----      ----

Discount rate                                  6.50%       7.50%      8.00%                6.50%      7.50%     8.00%
Expected return on  plan assets                9.25%       9.50%      9.50%                  n/a        n/a       n/a
Rate of compensation increase                  4.00%       4.00%      4.00%                4.00%      4.00%     4.00%
Health care cost trend rate                      n/a         n/a        n/a               10.00%      8.50%     7.50%
Ultimate health care cost trend rate             n/a         n/a        n/a                5.00%      5.00%     5.50%
Year achieved                                    n/a         n/a        n/a                 2011       2009      2005
Measurement Date                               Jan 1       Jan 1      Jan 1                Jan 1      Jan 1     Jan 1
</TABLE>

      The effect of a one-percentage-point increase or decrease in the assumed
health care cost trend rate on total service and interest cost is less than
$100,000.

Pension Plan Contributions

        While the investment performance over the 2000-2002 period and the
recent decline in discount rates have significantly reduced the level of pension
income, the pension trust has been and remains adequately funded. No
contributions have been required since 1997, and the Company does not anticipate
making contributions to the funded pension plan in 2004. As such, these declines
in pension income have had no impact on the Company's cash flows.

Pension Plan Asset Allocations

        The Company's pension plan asset allocation at December 31, 2003 and
2002 and the target allocation for 2004 are as follows:


                                   Target             Percentage of Plan Assets
Asset Category                   Allocation                At December 31
                                 ----------                --------------
                                    2004               2003               2002
                                    ----               ----               ----
Equity Securities                    70%               71%                 73%
Debt Securities                      30%               29%                 27%

        The assets of the pension plan are invested in accordance with the
objectives of (1) fully funding the actuarial accrued liability for the pension
plan, (2) maximizing return within reasonable and prudent levels of risk in
order to minimize contributions, and (3) maintaining sufficient liquidity to
meet benefit payment obligations on a timely basis. These objectives have been
based on a ten-year investment horizon, so that interim fluctuations should be
viewed with appropriate perspective. The pension plan operates with several risk
and control procedures, including ongoing reviews of liabilities, investment
objectives, investment managers and performance expectations. Transactions
involving certain types of investments are prohibited. Equity securities held by
the pension plan during the above periods did not include SCANA Corporation
common stock.

        In developing the expected long-term rate of return assumptions,
management continually evaluates the pension plan's historical cumulative actual
returns over several periods, all of which returns have been in excess of
related broad indices, and management anticipates that the pension 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 a target asset
allocation of 70% with equity managers and 30% with fixed income managers.
Management regularly reviews such allocations and periodically rebalances the
portfolio to the targeted allocation when considered appropriate.

Long-Term Equity Compensation Plan

      The Long-Term Equity Compensation Plan provides for grants of incentive
and nonqualified stock options, stock appreciation rights, restricted stock,
performance shares and performance units to certain key employees and
non-employee directors. The plan currently authorizes the issuance of up to five
million shares of the Company's common stock, no more than one million of which
may be granted in the form of restricted stock.

      A summary of activity related to grants of nonqualified stock options
follows:

                                                                    Weighted
                                                Number of            Average
                                                 Options         Exercise Price
   ----------------------------------------- ----------------- -----------------
   Outstanding - December 31, 2000                 160,429            25.53
   Granted                                         716,368            27.43
   Exercised                                               -            n/a
   Forfeited                                       (74,516)           26.93
   ----------------------------------------- -----------------
   ----------------------------------------- -----------------
   Outstanding - December 31, 2001                 802,281            27.11
   ----------------------------------------- -----------------
   ----------------------------------------- -----------------
   Granted                                      1,116,638             27.56
   Exercised                                     (103,677)            27.12
   Forfeited                                       (97,332)           27.38
   ----------------------------------------- -----------------
   Outstanding - December 31, 2002               1,717,910            27.39
   ----------------------------------------- -----------------
   Granted                                                 -            n/a
   Exercised                                      (203,052)           27.41
   Forfeited                                       (21,173)           27.50
   ----------------------------------------- -----------------
   ----------------------------------------- -----------------
   Outstanding - December 31, 2003              1,493,685             27.39
   ----------------------------------------- -----------------
<TABLE>
<CAPTION>

      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, 2003
follows:

                                            Options Outstanding                           Options Exercisable

                                                Weighted
         Range                                  Average             Weighted                           Weighted
          Of                  Number           Remaining             Average            Number          Average
       Exercise                 of            Contractual           Exercise              Of           Exercise
        Prices               Options        Life (in years)           Price            Options           Price
------------------------ ----------------- ------------------- -------------------- --------------- ----------------
<S>    <C>       <C>        <C>                   <C>                <C>               <C>              <C>
       $25.50 to $29.60     1,493,685             7.6                $27.39            648,392          $27.19
------------------------ ----------------- ------------------- -------------------- --------------- ----------------
</TABLE>

      At December 31, 2002 and 2001exercisable options totaled 274,306 at a
weighted average exercise price of $26.91 and 47,275 at a weighted average
exercise price of $25.53, respectively.

      For purposes of the pro forma information presented in Note 1O, 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 and 2001 was $4.67 and $5.13, respectively, and was estimated
using the Black-Scholes Option pricing model with the following weighted average
assumptions. No options were granted in 2003.

                                                2002           2001
                                                ----           ----
Expected life of options (years)                   7              7
Risk free interest rate                         4.64%         5.08%
Volatility of underlying stock                     21%           22%
Dividend yield of underlying stock               4.4%           4.2%

4. LONG-TERM DEBT

        The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2004 through 2008 are summarized as follows:

  Year              Amount             Year              Amount
-------------- ----------------- ------------------ -----------------
                     (Millions of dollars)

  2004               $202              2007                $71
  2005                197              2008                161
  2006                381
-------------- ----------------- ------------------ -----------------

        Approximately $35.5 million of the long-term debt maturing in 2004 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, 2003 SCE&G had not yet
borrowed under the agreement.


        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.

        SCE&G has a three-year revolving line of credit totaling $75.0 million,
expiring in 2005, that provides a source of liquidity in addition to other lines
of credit..

        Substantially all of SCE&G's and GENCO's utility plant is pledged as
collateral in connection with long-term debt.

        On February 11, 2004 GENCO issued $100 million of senior secured
promissory notes maturing February 1, 2024 and bearing a fixed interest rate of
5.49%. Proceeds from this issuance will be used to support GENCO's construction
program and to repay intercompany advances borrowed for that purpose.


<PAGE>



5. SHORT-TERM BORROWINGS

        Details of lines of credit (including uncommitted lines of credit) and
short-term borrowings at December 31, 2003 and 2002, are as follows:

Millions of dollars                                 2003             2002
--------------------------------------------------------------- ---------------

Lines of credit (total and unused)
    Committed                                        $625             $475
    Uncommitted                                        113 (1)          113

Commercial paper outstanding (270 or fewer days):

SCE&G                                               $94.4           $127.6
Weighted average interest rate                         1.15%            1.40%

Fuel Company                                         $45.7           $50.1
Weighted average interest rate                         1.15%            1.38%

PSNC Energy                                          $55.2           $31.1
Weighted average interest rate                          1.17%           1.42%

Total                                              $195.3           $208.8
Weighted average interest rate                         1.16%            1.40%

(1) Includes a $78 million line that either the Company or SCE&G may use.

        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 14, 2004. The credit agreement
provides for a maximum of $125 million to be outstanding at any time. Since the
credit agreement expires within one year, commercial paper outstanding is
classified as short-term debt.

6. 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, 2003
approximately $44 million of retained earnings were restricted by this
requirement as to payment of cash dividends on SCE&G's common stock.

       Cash dividends on common stock were declared during 2003, 2002 and 2001
at an annual rate per share of $1.38, $1.30 and $1.20, respectively.


<PAGE>



        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, 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
    Other comprehensive income          2              3               5
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Balance, December 31, 2003             $2            $4               $6
===============================================================================

       During 2003, no unrealized gains (losses) on securities were reclassified
into net income (loss). The Company recognized a gain of $3.9 million , net of
tax, as a result of qualifying cash flow hedges whose hedged transactions
occurred during the year ended December 31, 2003.

       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 (DTAG) 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 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.

7. PREFERRED STOCK

       Retirements under sinking fund requirements are at par values. The
aggregate of the annual amounts of purchase or sinking fund requirements for
preferred stock for the years 2004 through 2008 is $2.7 million. The call
premium of the respective series of preferred stock in no case exceeds the
amount of the annual dividend.

       Changes in "Total Preferred Stock (Subject to purchase or sinking funds)"
during 2003, 2002 and 2001 are summarized as follows:

                                      Number of Shares   Millions of Dollars
-------------------------------------------------------------------------------
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
   Shares Redeemed  - $50 par value          (6,378)                 (0.3)
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Balance at December 31, 2003               193,595                  $9.7
===============================================================================

       On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned
subsidiary of SCE&G, issued $50 million of 7.55% Trust Preferred Securities,
Series A. On May 21, 2003 SCE&G effected the redemption of the Trust Preferred
Securities.


<PAGE>



8. INCOME TAXES
<TABLE>
<CAPTION>

       Total income tax expense attributable to income (before the cumulative
effect of an accounting change) for 2003, 2002 and 2001 is as follows:

Millions of dollars                                                   2003              2002              2001
--------------------------------------------------------------- ----------------- ----------------- -----------------
Current taxes:
<S>                                                                   <C>              <C>                <C>
      Federal                                                         $63.1            $174.6             $91.2
      State                                                             12.2               9.0              11.2
      Foreign                                                               -              1.0                  -
--------------------------------------------------------------- ----------------- ----------------- -----------------
--------------------------------------------------------------- ----------------- ----------------- -----------------
            Total current taxes                                        $75.3            184.6             102.4
--------------------------------------------------------------- ----------------- ----------------- -----------------
--------------------------------------------------------------- ----------------- ----------------- -----------------
Deferred taxes, net:
      Federal                                                           24.6          (178.5)             182.5
      State                                                               0.3              0.8               1.7
--------------------------------------------------------------- ----------------- ----------------- -----------------
--------------------------------------------------------------- ----------------- ----------------- -----------------
            Total deferred taxes                                        24.9          (177.7)             184.2
--------------------------------------------------------------- ----------------- ----------------- -----------------
--------------------------------------------------------------- ----------------- ----------------- -----------------
Investment tax credits:
      Deferred - State                                                   5.0              5.0                5.0
      Amortization of amounts deferred - State                          (1.8)            (1.7)              (1.5)
      Amortization of amounts deferred - Federal                        (4.0)            (4.0)              (4.0)
--------------------------------------------------------------- ----------------- ----------------- -----------------
            Total investment tax credits                                (0.8)            (0.7)              (0.5)
--------------------------------------------------------------- ----------------- ----------------- -----------------
Non-conventional fuel tax credits:
      Deferred - Federal                                                35.7             29.8               18.7
--------------------------------------------------------------- ----------------- ----------------- -----------------
            Total income tax expense                                 $135.1            $36.0             $304.8
=============================================================== ================= ================= =================

       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 the cumulative effect of an accounting change) is
reconciled as follows:

Millions of dollars                                                    2003             2002              2001
----------------------------------------------------------------- --------------- ----------------- -----------------

Income before cumulative effect of accounting change                  $282.0            $87.9              $539.3
Income tax expense                                                      135.1             36.0              304.9
Preferred stock dividends                                                 9.1             11.2                11.2
----------------------------------------------------------------- --------------- ----------------- -----------------
----------------------------------------------------------------- --------------- ----------------- -----------------
      Total pre-tax income                                            $426.2           $135.1              $855.4
================================================================= =============== ================= =================
================================================================= =============== ================= =================

Income taxes on above at statutory federal income tax rate            $149.2                $47.3            $299.4
Increases (decreases) attributed to:
   State income taxes (less federal income tax effect)
                                                                         10.2     8.5               10.7
    Non-deductible book amortization of acquisition adjustments
                                                                             -    -                 5.0
    Allowance for equity funds utilized during construction
                                                                         (6.7)    (7.9)             (5.2)
    Deductible dividends - Stock Purchase Savings Plan
                                                                         (4.9)    (4.5)             (1.1)
    Amortization of federal investment tax credits
                                                                         (4.0)    (4.0)             (4.0)
    Other differences, net
                                                                         (8.7)    (3.4)                           -
----------------------------------------------------------------- --------------- ----------------- -----------------
----------------------------------------------------------------- --------------- ----------------- -----------------
        Total income tax expense                                      $135.1                $36.0            $304.8
================================================================= =============== ================= =================
</TABLE>



<PAGE>



       The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $790.9 million at December 31, 2003 and
$751.1 million at December 31, 2002 (see Note 1I), are as follows:

Millions of dollars                            2003              2002
---------------------------------------------------------- ------------------
Deferred tax assets:
   Nondeductible reserves                       $70.6             $66.9
   Unamortized investment tax credits            59.9              61.0
    Investments in equity securities             43.3              25.0
   Deferred compensation                         22.3              21.2
   Other                                         40.5              26.3
---------------------------------------------------------- ------------------
        Total deferred tax assets              236.6              200.4
---------------------------------------------------------- ------------------

Deferred tax liabilities:
   Property, plant and equipment                889.2             814.4
   Pension  plan benefit income                   94.5             93.0
   Deferred fuel costs                            13.6             17.9
   Other                                          30.2             26.2
---------------------------------------------------------- ------------------
        Total deferred tax liabilities        1,027.5             951.5
---------------------------------------------------------- ------------------
Net deferred tax liability                     $790.9           $751.1
========================================================== ==================

       The Internal Revenue Service has completed and closed examinations of the
Company's consolidated federal income tax returns through the tax year ended in
2000, with the exception of the Company's interest in the synthetic fuel
partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it
is in the process of closing this partnership examination with no changes being
proposed, and that a formal closing letter is forthcoming. The IRS makes no
challenge to the declaration that the synthetic fuel facility was properly
placed in service, and takes no issue with the evidence submitted demonstrating
that the facility produces a qualifying fuel. The Company continues to believe
that all of its synthetic fuel tax credits have been properly claimed.

9. FINANCIAL INSTRUMENTS

       The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2003 and 2002 are as follows:
<TABLE>
<CAPTION>

Millions of dollars                                                     2003                         2002
----------------------------------------------------------- ----------------------------- ----------------------------
                                                                             Estimated                    Estimated
                                                              Carrying         Fair         Carrying        Fair
                                                               Amount          Value         Amount         Value
----------------------------------------------------------- -------------- -------------- ------------- --------------
Assets:
<S>                                                             <C>            <C>           <C>            <C>
    Cash and temporary cash investments                         $135.8         $135.8        $373.7         $373.7
    Investments                                                  177.2          178.1         231.0          281.3
Liabilities:
    Short-term borrowings                                        195.3          195.3          208.8         208.8
    Long-term debt                                             3,427.4        3,654.8       3,247.5        3,512.9
    Preferred stock (subject to purchase or sinking funds)          9.7            8.8          10.0            8.6
----------------------------------------------------------- -------------- -------------- ------------- --------------
</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,
               certificates of deposit, 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 considered.

Investments

       Certain of the Company's 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, the Company
performs periodic assessments of whether any decline in the value of these
securities to amounts below the Company's cost basis is other than temporary.
When other than temporary declines occur, write-downs are recorded through
operations, and new (lower) cost bases are established.
The Company also holds investments in several partnerships and joint ventures,
some of which are accounted for using the equity method.

Telecommunications Investments

        At December 31, 2003 SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of the Company, held the equity and debt securities
of the following companies.
<TABLE>
<CAPTION>

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

<S>                   <C>                                                                  <C>
Magnolia Holding      6.2 million shares nonvoting common stock                            $2.1

ITC^DeltaCom          567.5 thousand shares of common stock                                  1.1
                      160.4 thousand shares series A 8% preferred stock,
                         convertible into 2.8 million shares of
                         common stock                                                      13.0
                      Warrants to purchase 506.9 thousand shares of common stock             1.1

Knology               2.6 million shares of common stock                                   23.1
                      2.2 million shares of nonvoting common stock                         19.6
                      13% senior unsecured notes due 2009, including
                         accrued interest                                                  49.5
                      Warrants to purchase 16.5 thousand shares of common stock                -
</TABLE>

         In May 2003 the Company's investment in ITC Holding Company, Inc. was
sold. The transaction resulted in the receipt of net after-tax cash proceeds of
approximately $48 million and the receipt of an investment interest in a newly
formed entity, Magnolia Holding Company LLC (Magnolia Holding). A book gain, net
of tax, of approximately $39 million was realized upon this transaction.
Magnolia Holding holds ownership interests in several Southeastern
communications companies.

        ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of
telecommunications services. The common shares of ITC^DeltaCom owned by SCH have
a market value of $3.4 million. The ITC^DeltaCom preferred shares owned by SCH
are classified as held to maturity due to their debt features, and the market
value is not readily determinable.


<PAGE>



        Knology, Inc. (Knology) is a broadband service provider of cable
television, telephone and internet services. In August 2003, Magnolia Holding
distributed its holdings in Knology preferred stock to Magnolia Holding's
members. As a result, SCH's basis in Magnolia Holding was reduced by, and SCH's
basis in Knology was increased by, approximately $6.2 million. During 2003, SCH
recorded impairment losses associated with its Knology investment totaling $34.6
million, net of taxes. These impairments were based upon valuation information
obtained in connection with the Magnolia Holding transaction and the subsequent
completion of Knology's initial public offering. SCH's investment in Knology's
common stock reflects the $9.03 trading price of such stock at December 31,
2003.

Derivatives

        SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended, requires the Company to recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and to measure those instruments at fair value. SFAS 133 further
provides that changes in the fair value of derivative instruments are either
recognized in earnings or reported as a component of other comprehensive income
(loss), depending upon the intended use of the derivative and the resulting
designation. The fair value of 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, apprises the Board of Directors with regard to the
management of risk and brings to the Board's attention any areas of concern.
Written policies define the physical and financial transactions that are
approved, as well as the authorization requirements and limits for transactions.

Commodities

        The Company uses derivative instruments to hedge forward purchases of
natural gas, which create market risks of different types. Instruments
designated as cash flow hedges are used to hedge risks associated with fixed
price obligations in a volatile market and risks associated with price
differentials at different delivery locations. The basic types of financial
instruments utilized are exchange-traded instruments, such as New York
Mercantile Exchange (NYMEX) futures contracts or options, and over-the-counter
instruments such as swaps, which are typically offered by energy and financial
institutions.

        As a result of adopting SFAS 133, the Company recorded a credit to other
comprehensive income (loss) of approximately $23.0 million, net of tax, as the
effect of the change in accounting principle (transition adjustment) on January
1, 2001. This amount represents the reclassification of unrealized gains that
were deferred and reported as liabilities at December 31, 2000. Substantially
all of this amount was reclassified into earnings in 2001 as a component of gas
cost.

        The Company recognized gains (losses) of approximately $3.9 million,
$(20.6) million and $(16.9) million, net of tax, as a result of qualifying cash
flow hedges whose hedged transactions occurred during the years ended December
31, 2003, 2002 and 2001, respectively. These amounts were recorded in cost of
gas. The Company estimates that most of the December 31, 2003 unrealized gain
balance of $4.9 million, net of tax, will be reclassified from accumulated other
comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas
cost if market prices remain stable. As of December 31, 2003, all of the
Company's cash flow hedges settle by their terms before the end of 2006.

        The Company recorded option premiums of $0.7 million and gains of $0.3
million, net of tax, as a result of qualifying fair value hedges during the year
ended December 31, 2003. The premiums and gains were recorded in cost of gas. As
of December 31, 2003 all of the Company's fair value hedges had settled.


<PAGE>



        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 provision for the recovery of actual gas costs incurred. PSNC Energy
records transaction fees and any realized gains or losses from derivatives
acquired as part of its hedging program in deferred accounts as a regulatory
asset or liability for the over or under recovery of gas costs.

        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
current asset or liability.

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 rate interest payments and are designated as fair value hedges of certain
debt instruments. The Company may terminate a swap agreement and may replace it
with a new swap also designated as a fair value hedge.

        Payments received upon termination of a swap are recorded as basis
adjustments to long-term debt and are amortized as reductions to interest
expense over the term of the underlying debt. The fair value of interest rate
swaps is recorded within other deferred debits on the balance sheet. The
resulting credits serve to reflect the hedged long-term debt at its fair value.
Periodic receipts or payments related to the interest rate swaps are credited or
charged to interest expense as incurred.

        The Company received a payment to terminate a swap totaling $29.3
million in 2002. This amount is being amortized over the ten-year term of the
underlying debt it formerly hedged. At December 31, 2003 the estimated fair
value of the Company's swaps totaled $6.3 million related to combined notional
amounts of $333.1 million.

        In anticipation of the issuance of debt, the Company uses interest rate
lock or similar agreements to manage interest rate risk. Payments received or
made upon termination of such agreements are recorded within other deferred
debits on the balance sheet and are amortized to interest expense over the term
of the underlying debt. In connection with the issuance of First Mortgage Bonds
in May 2003, the Company paid approximately $11.9 million upon the termination
of a treasury lock agreement. In connection with the issuance of First Mortgage
Bonds in December 2003, the Company paid approximately $3.5 million upon the
termination of a forward starting interest rate swap.

10. COMMITMENTS AND CONTINGENCIES

A.       Lake Murray Dam Reinforcement

         In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam
in order to comply with new federal safety standards. 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, 2003 totaled approximately $169 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 $10.9 billion. Each
reactor licensee is currently liable for up to $100.6 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $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 $67.1 million per incident, but not
more than $6.7 million per year.

        Congress failed to renew the Price-Anderson Indemnification Act when it
expired in 2003. The Act is expected to be renewed with only modest changes in
2004. The delayed renewal has no impact on the Company due to the
"grandfathered" status of existing licensees that are covered under the expired
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 retrospective assessments under certain conditions to cover insurer's
losses. Based on the current annual premium, SCE&G's portion of the
retrospective premium assessment would not exceed $15.8 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 deferred and amortized
with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $10.9
million at December 31, 2003. 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 by the
end of 2004, with certain monitoring and other activities continuing until 2007.
As of December 31, 2003, SCE&G has spent approximately $19.7 million to
remediate the Calhoun Park site, and expects to spend an additional $2.2
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. In addition, in March 2003 SCE&G signed a consent agreement with
DHEC related to a site formerly owned by SCE&G. The site contained residue
material that was moved from the Columbia MGP. The removal action for this site
has been completed. SCE&G anticipates that major remediation activities for the
three owned sites will be completed before 2006. As of December 31, 2003, SCE&G
has spent approximately $3.0 million related to these three sites, and expects
to spend an additional $5.0 million.

       Public Service Company of North Carolina, Incorporated

       PSNC Energy is responsible for environmental cleanup at five sites in
North Carolina on which MGP residuals are present or suspected. PSNC Energy's
actual remediation costs for these sites will depend on a number of factors,
such as actual site conditions, third-party claims and recoveries from other
PRPs. PSNC Energy has recorded a liability and associated regulatory asset of
approximately $7.0 million, which reflects the estimated remaining liability at
December 31, 2003. Amounts incurred and deferred to date that are not currently
being recovered through gas rates are approximately $2.2 million. Management
believes that all MGP cleanup costs incurred will be recoverable through gas
rates.

D.     Franchise Agreements

       See Notes 1B and 4 for a discussion of the electric and gas franchise
agreements between SCE&G and the city 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 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.


<PAGE>



         In 2001 a subsidiary of the Company entered into, in the ordinary
course of business, a fifteen-year take-and-pay contract with an unaffiliated
natural gas supplier to purchase natural gas beginning in the spring of 2004. In
December 2002, as a result of the failure of the supplier and its guarantor to
meet contractual obligations related to credit support provisions, the
subsidiary terminated the contract and the supplier initiated arbitration. In
December 2003, an unrelated, creditworthy third party agreed to serve as
supplier for the Company for the fifteen-year term with similar terms and
conditions and a lower daily volume, and as a result the arbitration was
dismissed and both parties executed releases of claims.

        On August 21, 2003, SCE&G was served as a co-defendant in a purported
class action lawsuit styled as Collins v. Duke Energy Corporation, Progress
Energy Services Company, and South Carolina Electric & Gas Company, in South
Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The
plaintiffs are seeking damages for the alleged improper use of electric
transmission easements but have not asserted a dollar amount for their claims.
Specifically, the plaintiffs contend that the licensing of attachments on
electric utility poles, towers and other facilities to non-utility third parties
or telecommunication companies for other than the electric utilities' internal
use along the electric transmission line right-of-way constitutes a trespass.
The Company is confident of the propriety of its actions and intends to mount a
vigorous defense. 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.

        A complaint was filed on October 22, 2003 against SCE&G by the State of
South Carolina alleging that SCE&G violates the Unfair Trade Practices Act by
charging municipal franchise fees to some customers residing outside a
municipality's limits. The complaint also alleges that SCE&G failed to obey,
observe, or comply with the lawful order of the SCPSC by charging franchise fees
to those not residing in a municipality. The complaint seeks restitution to all
affected customers and penalties up to $5,000 for each separate violation. SCE&G
is confident of the reasonableness of its actions and intends to mount a
vigorous defense. The allegations contained in the complaint are the subject of
a similar lawsuit that was filed and served on SCE&G, for which a Motion to
Dismiss is pending. The allegations are also the subject of a purported class
action lawsuit filed on or about December 12, 2003 against Duke Energy
Corporation, Progress Energy Services Company and SCE&G. SCE&G further believes
that the resolution of these actions will not have a material adverse impact on
its results of operations, cash flows or financial condition. In addition, SCE&G
filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann.
R.103-836. The petition requests that the SCPSC exercise its jurisdiction to
investigate the operation of the municipal franchise fee collection requirements
applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to
correct any past franchise fee billing errors, to adopt improvements in the
system which will reduce such errors in the future, and to adopt any regulation
which the SCPSC deems just and proper to regulate the franchise fee collection
process.

        The Company, SCE&G and PSNC Energy are also engaged in various other
claims and litigation incidental to their 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 $12.4 million, $11.5 million and $12.1
million in 2003, 2002 and 2001, respectively. Future minimum rental payments
under such leases are as follows:

                                     Millions of dollars
                        2004              $16.6
                        2005                13.1
                        2006                12.2
                        2007                10.4
                        2008                  9.7
                        Thereafter            9.2
                                          -------
                                               $71.2


<PAGE>



        At December 31, 2003 minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$10 million.

G.      Purchase Commitments

        Purchase commitments under forward contracts for natural gas purchases,
gas transportation capacity agreements, coal supply contracts, construction
projects and other commitments are as follows:

                             Millions of dollars
                        2004              $1,348.6
                        2005                   725.6
                        2006                   529.9
                        2007                   387.4
                        2008                   366.8
                                  Thereafter        3,638.4
                                                  ---------
                                          $6,996.7

        Forward contracts for natural gas purchases include customary
"make-whole" or default provisions, but are not considered to be "take-or-pay"
contracts.

        In addition, included in purchase commitments are customary purchase
orders under which the Company has the option to utilize certain vendors without
the obligation to do so. The Company may terminate such commitments without
penalty.

11. SEGMENT OF BUSINESS INFORMATION

        The Company's reportable segments are described below. The accounting
policies of the segments are the same as those described in the summary of
significant accounting policies. The Company records intersegment sales and
transfers of electricity and gas based on rates established by the appropriate
regulatory authority. Nonregulated sales and transfers are recorded at current
market prices.

         Electric Operations is comprised of the electric operations 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 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. SCE&G and PSNC
Energy are regulated by the SCPSC and the NCUC, respectively. 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 the Georgia 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. Due to the sale of ITC Holding and DTAG, Telecommunications
Investments no longer meets SFAS 131 criteria as a reportable segment and is
reclassified into All Other for 2003 and 2002.


<PAGE>



       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      All    Adjustments/ Consolidated
                                                                    Gas
           2003              Operations DistributionTransmission Marketing  Marketing    Other   Eliminations    Total
---------------------------- ---------- ----------- ------------ ---------- ----------- -------- ------------ ------------

<S>                           <C>           <C>        <C>         <C>         <C>        <C>        <C>        <C>
Customer Revenue              $1,466        $869       $217        $448        $416       $56        $(56)      $3,416
Intersegment Revenue                            -        303            -           -     276        (584)             -
                                 5
Operating Income                  426         77          16         n/a         n/a         1         31           551
Interest Expense                     7         21           5          4           -         1        162           200
Depreciation & Amortization      183           47           7          1           -         9          (9)         238
Income Tax Expense                  2          19           4         12           (1)       9         90           135
(Benefit)
Net Income (Loss)                 n/a        n/a         n/a          20                     4        259           282
                                                                               (1)
Segment Assets                 5,038      1,477          334         133          53      699         715        8,449
Expenditures for Assets          655          68          18            -           -      35          (26)         750
Deferred Tax Assets                 3          6           5            6           2      44          (66)            -
---------------------------- ---------- ----------- ------------ ---------- ----------- -------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>

---------------------------- ---------- ----------- ------------ ---------- ----------- -------- ------------ ------------
                             Electric      Gas          Gas      Retail       Energy      All    Adjustments/ Consolidated
                                                                    Gas
           2002              Operations DistributionTransmission Marketing  Marketing    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                 5          1        254            -          -      289       (549)               -
Operating Income                  417         69            6        n/a         n/a        -          22            514
Interest Expense                    8         21            5           3          1       12        149             199
Depreciation & Amortization      166          47            6           -          1        7          (7)           220
Income Tax Expense                  3         13            -           6         (1)     (81)        96              36
(Benefit)
Net Income (Loss)                n/a         n/a         n/a          14                 (170)        14            (142)
                                                                                -
Segment Assets                 4,511      1,406          321         128          53      691        964          8,074
Expenditures for Assets          617          68          17            -          -       15        (23)            694
Deferred Tax Assets                 6           6           6           5          2       26        (51)               -
---------------------------- ---------- ----------- ------------ ---------- ----------- -------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>

------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------
                          Electric      Gas          Gas       Retail      Energy      Telecom      All    Adjustments/ Consolidated
                                                                  Gas
           2001           Operations DistributionTransmission  Marketing  Marketing  Investments   Other   Eliminations    Total
------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------

<S>                        <C>          <C>          <C>         <C>        <C>                      <C>       <C>        <C>
Customer Revenue           $1,369       $793         $222        $454       $613            -        $49       $(49)      $3,451
Intersegment Revenue                 5         1         256             -          -          -        270       (532)
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                 3,857       1,461          329          99         96        784         330        866        7,822
Expenditures for Assets           414         90           21           4           2          -          17          -         548
Deferred Tax Assets                  6         -            4           5           6          -           -       (21)
---------------------------- ---------- ----------- ------------- ---------- ---------- ------------ -------- ------------ ---------
</TABLE>

       Revenues and assets from segments below the quantitative thresholds are
attributable to eight other direct and indirect wholly owned subsidiaries of the
Company. These subsidiaries conduct nonregulated operations in energy-related
and telecommunications industries. None of these subsidiaries met the
quantitative thresholds for determining reportable segments in 2003 or 2002, and
none met the quantitative thresholds in 2001 except Telecommunications
Investments.

       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, net 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 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 adjustments to net income
and income tax expense include the cumulative effect of the accounting change
described in Note 1G.

       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, net for SCE&G's Electric Operations
and Gas Distribution, and all assets for PSNC Energy and the remaining segments.
As a result, adjustments to assets include non-utility plant and non-fixed
assets for SCE&G.

       Adjustments to Interest Expense, Income Tax Expense (Benefit) 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. Expenditures for
Assets are adjusted for AFC. Deferred Tax Assets are adjusted to net them
against deferred tax liabilities on a consolidated basis.

12. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>

2003                                                              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                                         $1,069       $726        $751       $870       $3,416
Operating income                                                     168        100        150        133           551
Net income (loss)                                                     84         74         84          40          282
Basic and diluted earnings (loss)  per share                          .75       .67        .76         .36         2.54
-------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------

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

Total operating revenues                                          $822        $649        $694       $789       $2,954
Operating income                                                   153           89        154         118          514
Income (loss) before cumulative effect of accounting change         (72)         40          78         42           88
Cumulative effect of accounting change, net of taxes               (230)           -          -           -       (230)
Net income (loss)                                                  (302)         40         78          42        (142)
Basic and diluted earnings (loss)  per share                      (2.88)        .38        .74         .47       (1.34)
-------------------------------------------------------------- ------------ ---------- ----------- ---------- -----------
</TABLE>



<PAGE>





















                      SOUTH CAROLINA ELECTRIC & GAS COMPANY












Item 7.   Management's Discussion and Analysis of Financial Condition
              and Results of Operations...................................  88

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk...... 102

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
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, including competition from alternate fuels in industrial
interruptible markets, (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.

OVERVIEW

        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.

Electric Operations

        The electric operations segment is comprised of the electric operations
of SCE&G and Fuel Company, and is primarily engaged in the generation,
transmission and distribution of electricity in South Carolina. At December 31,
2003 SCE&G provided electricity to over 570,000 customers. Fuel Company
acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and
sulfur dioxide emission allowance requirements and is consolidated with SCE&G
for financial reporting purposes.

        Operating results for electric operations are primarily driven by
customer demand for electricity, the ability to control costs and allowed rates
to be charged to customers. Embedded in these rates is an allowed regulatory
return on equity, which is currently 12.45%. Demand for electricity is primarily
affected by weather, customer growth and the economy. In addition, significant
legislative and regulatory matters could significantly impact the results of
operations and cash flows for the electric operations segment.

        In South Carolina the state legislature is not actively pursuing
electric restructuring. However, both houses of the U.S. Congress passed energy
legislation in 2003, with the House of Representatives passing an energy
conference report. The Senate failed to pass the conference report due to its
inability to reach a compromise on certain key issues unrelated to utilities. If
a compromise is reached in 2004, such legislation is expected to contain
provisions that would repeal PUHCA and transfer additional regulatory authority
to FERC. This legislation may also impose stringent requirements on retail
electric suppliers to generate electricity from renewable energy resources,
which sources may or may not include hydroelectric generation. In addition,
largely in response to the August 2003 blackout in eight northern states and
parts of Canada, the energy legislation would likely include provisions to
develop and enforce reliability standards for high-voltage transmission systems
and to expedite construction of transmission lines. SCE&G cannot predict whether
such legislation will be enacted, and if it is, the conditions it would impose
on utilities.


<PAGE>



        If the energy legislation stalls in 2004, or if it fails to address
certain issues, FERC is expected to proceed with regulatory initiatives that
would significantly change the country's existing regulatory framework governing
transmission, open access and energy markets and would attempt, in large
measure, to standardize the national energy market. In July 2002 FERC issued a
Notice of Proposed Rulemaking on Standard Market Design (SMD) which FERC
supplemented with the issuance of a "white paper" in April 2003. If implemented,
the proposed rule could 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 FERC's action to determine
potential effects on SCE&G's operations. Additional directives from FERC are
expected, and would likely be significantly influenced by the energy legislation
discussed in the preceding paragraph.

        The North American Electric Reliability Council (NERC) is comprised of
utilities and other market participants who voluntarily develop and comply with
NERC policies and standards which govern the planning and operation of the
nation's interconnected bulk power system (the Grid). Currently these policies
and standards are enforceable only through voluntary compliance by NERC members.
Since the August 2003 blackout, and in response to issues identified during
investigation of the blackout, NERC has been developing additional reliability
standards, policies, and procedures. NERC is working with the regions and
utilities in North America to strengthen existing enforcement and compliance
programs, and is seeking to develop contracts between the regions and utility
members to require compliance with these standards. NERC is also actively
pursuing federal legislation to provide it with the authority to enforce
reliability standards on all market participants, not just utilities. SCE&G
continues to work with NERC and directly with other utilities to develop
additional reliability policies and standards and continues to comply with
NERC's existing policies and standards.

Gas Distribution

        The gas distribution segment is comprised of the local distribution
operations of SCE&G and is primarily engaged in the purchase and sale, primarily
at retail, of natural gas in portions of South Carolina. At December 31, 2003
this segment provided natural gas to more than 276,000 customers.

        Operating results for gas distribution are primarily influenced by
customer demand for natural gas, the ability to control costs and allowed rates
to be charged to customers. Embedded in these rates is an allowed regulatory
return on equity, which is currently 12.25%. Demand for natural gas is primarily
affected by weather, customer growth, the economy and, for commercial and
industrial customers, the availability and price of alternate fuels. Natural gas
competes with electricity, propane and heating oil to serve the heating and, to
a lesser extent, other household energy needs of residential and small
commercial customers. This competition is generally based on price and
convenience. Large commercial and industrial customers often have the ability to
switch from natural gas to an alternate fuel, such as propane or fuel oil.
Natural gas competes with these alternate fuels based on price. As a result, any
significant disparity between supply and demand, either of natural gas or of
alternate fuels, and due either to production or delivery disruptions or other
factors, will affect price and impact SCE&G's ability to retain large commercial
and industrial customers.

RESULTS OF OPERATIONS

Net Income

        Net income and the percent change from the previous year for the years
2003, 2002 and 2001 were as follows:

Millions of dollars                          2003        2002       2001
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
Net income                                  $220.5      $219.6     $221.9
Percent increase (decrease) in net income      0.41%                (12.50%)
                                                       (1.04%)

o       2003 vs 2002  Net income increased slightly primarily due to higher
                      electric margins of $36.8 million, higher gas margins of
                      $2.6 million, reduction of preferred dividend requirements
                      of $0.9 million and other of $1.3 million, partially
                      offset by higher operations and maintenance expenses of
                      $15.9 million (including $7.1 due to lower pension
                      income), higher depreciation and amortization expense of
                      $10.9 million, higher property taxes of $7.2 million and
                      higher interest expense of $6.7 million.

o       2002 vs 2001 Net income decreased primarily due to higher operations and
                     maintenance expenses of $30.4 million (including
                      $6.3 million due to lower pension income), higher property
                      taxes of $6.5 million, and higher interest expense
                      of  $4.7 million, partially offset by higher electric
                     margins of  $37.3 million.

     Pension Income

     Pension income was recorded on SCE&G's financial statements as follows:
<TABLE>
<CAPTION>

Millions of dollars                                                 2003       2002        2001
---------------------------------------------------------------------------- ---------- -----------
---------------------------------------------------------------------------- ---------- -----------
Income Statement Impact:
<S>                                                                <C>         <C>         <C>
  (Component of) reduction in employee benefit costs               $(1.0)      $10.5       $20.7
  Other income                                                       8.2        11.2         12.7
Balance Sheet Impact:
  (Component of) reduction in capital expenditures                  (0.3)         3.1         5.9
Component of (reduction in) amount due to Summer Station co-owner   (0.1)         0.7         1.8
---------------------------------------------------------------------------- ---------- -----------
Total Pension Income                                                $6.8       $25.5      $41.1
============================================================================ ========== ===========
</TABLE>

     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 2003 decreased significantly compared
to 2002 and 2001, primarily as a result of a less favorable investment market.
See also the discussion of pension accounting in Critical Accounting Policies.

     Allowance for Funds Used During Construction (AFC)

     AFC is a utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is shown on the
balance sheet as construction work in progress) is capitalized. 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 7.8% of
income before income taxes in 2003, 9.3% in 2002 and 6.5% in 2001.

     The decrease in AFC for 2003 vs 2002 is primarily the result of the
completion of the Urquhart Station repowering project in June 2002. In addition,
in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper
County generating project expenditures as of December 31, 2002 and other
construction work in progress expenditures as of June 30, 2002 in its electric
rate base. At the time the expenditures were included in the rate base, AFC was
no longer calculated on those amounts. These decreases were partially offset by
increased AFC from subsequent construction expenditures related to the Jasper
County generating and Lake Murray Dam projects (see discussion at CAPITAL
PROJECTS).

     The increase in AFC for 2002 vs 2001 was primarily the result of increased
construction expenditures for the Urquhart Station repowering, Jasper County
generating and Lake Murray Dam projects.

Dividends Declared

     SCE&G's Board of Directors has declared the following dividends on common
stock held by SCANA during 2003:

  ------------------ ------------------ --------------------- ------------------
  Declaration Date   Dividend Amount    Quarter Ended         Payment Date
  ------------------ ------------------ --------------------- ------------------

  February 20, 2003  $35.3 million      March 31, 2003        April 1, 2003
  May 1, 2003        $36.5 million      June 30, 2003         July 1, 2003
  July 31, 2003      $37.0 million      September 30, 2003    October 1, 2003
  November 7, 2003   $36.0 million      December 31, 2003     January 1, 2004
  ------------------ ------------------ --------------------- ------------------



<PAGE>


Electric Operations

       Electric Operations is comprised of the electric operations of SCE&G and
Fuel Company. Electric operations sales margins for 2003, 2002 and 2001, were as
follows:
<TABLE>
<CAPTION>

Millions of dollars                             2003        % Change        2002       % Change       2001
------------------------------------------- ------------- ------------- ------------- ------------ ------------

<S>                                           <C>             <C>         <C>             <C>       <C>
Operating revenues                            $1,471.7        6.3%        $1,384.8        0.8%      $1,374.0
Less:  Fuel used in generation                    272.5       5.8%            257.5      15.0%          223.9
           Purchased power                        164.0       8.2%            151.6      35.2%          233.9
------------------------------------------- -------------               -------------              ------------
      Margin                                  $1,035.2        6.1%          $975.7       6.5%          $916.2
=========================================== ============= ============= ============= ============ ============

          o    2003 vs 2002 Margins  increased  primarily due to the increase in
               retail  electric  base rates  approved in January  2003  totaling
               $63.6 million and customer  growth and increased  consumption  of
               $23.2  million,  partially  offset by $27.3  million  due to less
               favorable  weather.  Fuel used in  generation  increased  by $9.3
               million due to the increased cost of natural gas and fuel oil for
               the Urquhart  combined cycle gas turbines and by $1.1 million due
               to the increased cost of nuclear fuel,  partially  offset by $5.5
               million  due  to  planned  plant  outages  throughout  the  year.
               Purchased power increased due to planned plant outages throughout
               the year.

          o    2002 vs 2001 Margins  increased  primarily due to more  favorable
               weather  of $31.9  million  and  customer  growth  and  increased
               consumption of $30.5 million.  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.
</TABLE>
<TABLE>
<CAPTION>

       MWh sales volume by classes, related to the electric margin above, were
as follows:

-------------------------------------------- ----------- ----------- ------------- ---------- -----------
                                                             %                         %
Classification (in thousands)                   2003        Change       2002       Change       2001
-------------------------------------------- ----------- ----------- ------------- ---------- -----------

<S>                                             <C>         <C>          <C>         <C>        <C>
Residential                                     6,998       (3.2%)       7,230       11.3%      6,494
Commercial                                      6,622       (0.5%)       6,658        5.9%       6,288
Industrial                                      6,548        0.7%        6,505        2.5%       6,348
Sale for resale (excluding interchange)         1,438       (0.7%)       1,448       30.0%       1,114
Other                                              500      (6.5%)          535       0.2%          534
-------------------------------------------- -----------             -------------            -----------
-------------------------------------------- -----------             -------------            -----------
Total territorial                              22,106       (1.2%)      22,376        7.7%      20,778
NMST                                               425    (40.0%)           709     (67.0%)       2,150
-------------------------------------------- -----------             -------------            -----------
-------------------------------------------- -----------             -------------            -----------
Total                                          22,531      (2.4%)       23,085        0.7%      22,928
============================================ =========== =========== ============= ========== ===========

          o    2003 vs 2002 Territorial sales volume decreased  primarily due to
               less favorable weather.  NMST volumes decreased  primarily due to
               planned outages at generation plants that reduced volumes
               available for resale.

          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
               (rather than in margin) beginning in the
                     third quarter 2002.
</TABLE>

<TABLE>
<CAPTION>

Gas Distribution

       Gas Distribution is comprised of the local distribution operations of
SCE&G. Gas distribution sales margins (including transactions with affiliates)
for 2003, 2002 and 2001 were as follows:

  Millions of dollars                     2003      % Change      2002      % Change       2001
  ------------------------------------- ---------- ------------ ---------- ------------ -----------

<S>                                      <C>          <C>        <C>         <C>          <C>
  Operating revenues                     $360.1       20.8%      $298.2      (12.6%)      $341.0
  Less:  Gas purchased for resale         268.8       27.3%        211.1     (16.1%)       251.6
  ------------------------------------- ----------              ----------              -----------
         Margin                           $91.3        4.8%        $87.1      (2.6%)       $89.4
  ===================================== ========== ============ ========== ============ ===========


          o    2003 vs 2002 Margin  increased  primarily due to customer  growth
               and increased consumption totaling $7.2 million, partially offset
               by a decrease in industrial  usage of $3.0 million  primarily due
               to an unfavorable competitive position of natural gas relative to
               alternate fuels.

          o    2002  vs 2001  Margin  decreased  primarily  as a  result  of the
               slowing economy and increased competition with alternate fuels.

       DT sales volume by classes, including transportation gas were as follows:

-------------------------------------------- ----------- ----------- ------------- ---------- -------------
Classification (in thousands)                                %                         %
                                                2003        Change       2002       Change        2001
-------------------------------------------- ----------- ----------- ------------- ---------- -------------

Residential                                    13,243       8.2%        12,242        8.8%       11,257
Commercial                                     12,322       5.2%        11,718         3.7%      11,305
Industrial                                     14,374      (9.8%)       15,939       11.4%       14,301
Transportation gas                               2,141     (9.8%)        2,373       (3.6%)        2,461
-------------------------------------------- -----------             -------------            -------------
                                                                                              -------------
Total                                          42,080      (0.5%)       42,272        7.5%       39,324
============================================ =========== =========== ============= ========== =============

          o    2003 vs 2002 Residential and commercial  sales volumes  increased
               primarily  due  to  more   favorable   weather.   Industrial  and
               transportation volumes decreased in 2003 primarily as a result of
               interruptible customers using their alternate fuel sources during
               the year.

          o    2002 vs 2001 Residential and commercial  sales volumes  increased
               primarily  due to  more  favorable  weather.  Industrial  volumes
               increased in 2002  primarily due to the volatility of the natural
               gas market in 2001,  resulting in  interruptible  customers using
               their alternate fuel sources during that year.

Other Operating Expenses

       Other operating expenses were as follows:

Millions of dollars                             2003        % Change        2002        % Change          2001
------------------------------------------- ------------- ------------- ------------- -------------- ---------------

Other operation and maintenance                $392.4          7.0%        $366.6         16.1%          $315.7
Depreciation and amortization                   188.1        10.3%          170.5          4.4%           163.4
Other taxes                                     120.6        10.7%          108.9         10.1%             98.9
------------------------------------------- -------------               -------------                ---------------
                                                                                                     ---------------
 Total                                         $701.1          8.5%        $646.0         11.8%          $578.0
=========================================== ============= ============= ============= ============== ===============

          o    2003 vs 2002 Other operation and maintenance  expenses  increased
               primarily due to lower pension income of $11.5 million, increased
               labor and benefit  costs of $9.8 million,  and increased  nuclear
               operating expenses of $4.5 million. Depreciation and amortization
               increased by $10.7 million due to normal net property  increases,
               by $4.2 million due to the  completion  of the  Urquhart  Station
               repowering  project  in  June  2002  and by $2.7  million  due to
               amortization of franchise fees.  Other taxes increased  primarily
               due to increased property taxes.

          o    2002 vs 2001 Other operation and maintenance  expenses  increased
               primarily due to lower pension income of $10.2 million, increased
               labor  and  benefit  costs of $19.3  million,  increased  nuclear
               refueling  maintenance  costs 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 by $4.8 million due to
               completion  of the Urquhart  Station  repowering  project in June
               2002 and by $2.2  million due to normal net  property  additions.
               Other taxes increased primarily due to increased property taxes.

</TABLE>

<PAGE>



Interest Expense

       Components of interest expense, excluding the debt component of AFC, were
as follows:
<TABLE>
<CAPTION>

Millions of dollars                 2003    % Change    2002     % Change     2001
----------------------------------------------------------------------------------------

<S>                                <C>       <C>       <C>          <C>      <C>
Interest on long-term debt, net    $134.3    10.1%     $122.0       8.1%     $112.9
Other interest expense                 5.3  (20.9%)        6.7     17.5%         5.7
-------------------------------------------          -----------            ------------
                                                                            ------------
 Total                             $139.6     8.5%     $128.7       8.5%     $118.6
========================================================================================
</TABLE>

o      2003 vs 2002   Interest expense increased by $10.9 million,
                      primarily due to a $22.0 million increase from additional
                      borrowings, which was partially offset by $10.2 million as
                      a result of lower interest rates.

o       2002 vs 2001 Interest expense increased by $11.9 million as a result of
                     increased borrowings which was partially offset by
                      $2.8 million as a result of lower interest rates.


Income Taxes

       Income taxes decreased approximately $5.2 million for the year 2003
compared to 2002 and decreased approximately $10.1 million for the year ended
2002 compared to 2001. Changes in income taxes are primarily due to changes in
operating income. SCE&G's effective tax rate has also been favorably impacted in
recent years by the flow-through of federal investment tax credits and the
recovery of the equity portion of AFC.

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.

       SCE&G's current estimates of its cash requirements for construction and
nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 2004-2006 are as follows:

------------------------------------- -------------- --------------
Type of Facilities          2004          2005           2006
------------------          ----          ----           ----
                                  (Millions of dollars)
SCE&G:
  Electric Plant:
       Generation           $197           $52           $135
       Transmission           45             51             42
       Distribution          105           113            119
       Other                  14             13             12
   Nuclear Fuel               22              5             31
   Gas                        23             21             23
   Common                     58             16             16
   Other                        2             2               -
------------------------------------- -------------- --------------
------------------------------------- -------------- --------------
       Total SCE&G          $466           $273           $378
------------------------------------- -------------- --------------



<PAGE>


<TABLE>
<CAPTION>

       SCE&G's contractual cash obligations as of December 31, 2003 are
summarized as follows:

                          Contractual Cash Obligations

                                                          Less than                                           More than
December 31, 2003                           Total           1year           1-3 years         4-5 years        5 years
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
(Millions of dollars)

Long-term and short-term
<S>                                         <C>             <C>                <C>               <C>           <C>
  debt (including interest)                 $4,386          $377               $649              $310          $3,050
Purchase obligations                            157            40                117                  -               -
Operating leases                                 62            13                 32                17                -
Other commercial commitments                    523           257                250                 6               10
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
         Total                              $5,128          $687              $1,048             $333          $3,060
---------------------------------------- ------------- ---------------- ------------------- --------------- --------------
</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. Also included in other
commercial commitments are obligations for the Lake Murray Dam reinforcement
project. See Note 10 to SCE&G's consolidated financial statements.

       Included in purchase obligations are customary purchase orders under
which SCE&G has the option to utilize certain vendors without the obligation to
do so. SCE&G may terminate such purchase obligations without penalty.

       SCE&G also has nuclear fuel obligations that are not listed in the
contractual cash obligations above. While no specific monetary amount is
specified for nuclear fuel contracts, SCE&G's two-thirds share of expected cost
is $22.2 million for the year 2004, a total of $54.6 million for the years
2005-2007, a total of $11.9 million for the years 2008-2009 and a total of $20.0
million for the years 2010-2011.

         The Company also has a legal obligation associated with the
decommissioning and dismantling of Summer Station that is not listed in the
contractual cash obligations above. See Note 1 to the Company's consolidated
financial statements.

       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.
<TABLE>
<CAPTION>

       Cash outlays for 2004 (estimated) and 2003 (actual) for certain
expenditures are as follows:

Millions of dollars                                                                      2004            2003
----------------------------------------------------------------------------------- --------------- ---------------

<S>                                                                                      <C>             <C>
Property additions and construction expenditures, net of AFC                             $443            $565
Nuclear fuel expenditures                                                                   22              25
Investments                                                                                 18              16
----------------------------------------------------------------------------------- --------------- ---------------
----------------------------------------------------------------------------------- --------------- ---------------
       Total                                                                             $483            $606
=================================================================================== =============== ===============
</TABLE>

       Included in cash outlays are the following specific projects:

o         FERC mandated that SCE&G's Lake Murray Dam be reinforced to comply
          with new federal safety standards. Construction for the project and
          related activities is expected to be complete in 2005 at a cost of
          approximately $275 million, of which approximately $169 million had
          been incurred through December 31, 2003.

o         Construction continues on SCE&G's 875 MW generation plant in Jasper
          County, South Carolina. The plant is expected to begin commercial
          operation in mid-2004 and cost approximately $450 million, of which
          approximately $425 million had been incurred through December 31,
          2003.


<PAGE>



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 the SCPSC and the SEC. The following
describes the financing programs currently utilized by SCE&G.
<TABLE>
<CAPTION>

       At December 31, 2003 SCE&G had available the following lines of credit
and short-term borrowings outstanding:

                                                                                                (Millions)
       Lines of credit:
       SCE&G
<S>                                                                                                 <C>
          Committed                                                                                 $400
          Uncommitted (1)                                                                          $78
       Short-term borrowings outstanding:
          Commercial paper (270 or fewer days)                                                     $140
          Weighted average interest rate                                                            1.15%
</TABLE>

       (1) Comprised of a $78 million uncommitted line that either SCE&G or the
Company may use.

        In addition, SCE&G has a three-year revolving line of credit totaling
$75 million, expiring in 2005, that provides backup liquidity.

       SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945
(Old Mortgage) and covering substantially all of its properties, prohibits the
issuance of additional bonds (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, 2003 the
Bond Ratio was 5.08. 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 $1,279
million at December 31, 2003), (ii) retirements of Class A Bonds (which
retirement credits totaled $156.9 million at December 31, 2003), 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, 2003 approximately $924.6 million 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, 2003 the New Bond Ratio was 4.87.

       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, 2003 the Preferred Stock Ratio was 1.55.

       The Articles also require the consent of a majority of the total voting
power of SCE&G's preferred stock before SCE&G may issue or assume any unsecured
indebtedness if, after such issue or assumption, the total principal amount of
all such unsecured indebtedness would exceed ten percent of the aggregate
principal amount of all of SCE&G's secured indebtedness and capital and surplus
(the ten percent test). No such consent is required to enter into agreements for
payment of principal, interest and premium for securities issued for pollution
control purposes. At December 31, 2003 the ten percent test would have limited
issuances of unsecured indebtedness to approximately $413.5 million. Unsecured
indebtedness at December 31, 2003 totaled approximately $94.4 million, and was
comprised of short-term borrowings.

       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, 2003 SCE&G had not borrowed
under the agreement, but expects to fully draw these amounts in 2004. Any such
amounts would be included in the ten percent test.

Financing Cash Flows

       During 2003 SCE&G experienced net cash inflows related to financing
activities of approximately $106 million primarily arising from borrowings in
support of SCE&G's construction program and for other general corporate
purposes.

       In anticipation of the issuance of debt, SCE&G may use interest rate lock
or similar agreements to manage interest rate risk. Payments received or made
upon termination of such agreements are recorded within other deferred debits or
credits on the balance sheet and are amortized to interest expense over the term
of the underlying debt. In connection with the issuance of First Mortgage Bonds
in May 2003, SCE&G paid approximately $11.9 million upon the termination of a
treasury lock agreement. In connection with the issuance of First Mortgage Bonds
in December 2003, SCE&G paid approximately $3.5 million upon the termination of
a forward starting interest rate swap.

            For additional information on significant financing transactions see
the Consolidated Statements of Capitalization and Note 4 to the consolidated
financial statements.

ENVIRONMENTAL MATTERS

       In the years 2001 through 2003, SCE&G's capital expenditures for
environmental control totaled approximately $168.5 million. These expenditures
were in addition to expenditures included in "Other operation and maintenance"
expenses, which were approximately $23.5 million, $23.7 million, and $17.0
million during 2003, 2002 and 2001, respectively. It is not possible to estimate
all future costs related to environmental matters, but forecasts for capitalized
environmental expenditures for SCE&G are $23.2 million for 2004 and $106.7
million for the four-year period 2005 through 2008. These expenditures are
included in SCE&G's construction program discussed in Liquidity and Capital
Resources and include the matters discussed below.

Electric Operations

      The Clean Air Act Amendments of 1990 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
indicated that it would finalize regulations by December 2004 for stricter
limits on mercury and other pollutants generated by coal-fired plants.

      The EPA has undertaken an aggressive enforcement initiative against the
utilities industry, and the DOJ has brought suit against a number of utilities
in federal court alleging violations of the CAA. At least two of these suits
have either been tried or have had substantive motions decided - one favorable
to the industry and one not. Neither is binding as precedent on SCE&G. Prior to
the suits, those utilities had received requests for information under Section
114 of the CAA and were issued Notices of Violation. The basis for these suits
is the assertion by the EPA that maintenance activities undertaken by the
utilities over the past 20 or more years constitute "major modifications" which
would have required the installation of costly Best Available Control Technology
(BACT). SCE&G has received and responded to Section 114 requests for information
related to Canadys and Wateree Stations. The regulations under the CAA provide
certain exemptions to the definition of "major modifications," including an
exemption for routine repair, replacement or maintenance. On October 27, 2003
EPA published a final revised NSR rule in the Federal Register with an effective
date of December 26, 2003. The new rule represents an industry - favorable
departure from certain positions advanced by the federal government in the NSR
enforcement initiative. However, on motion of several Northeastern states, the
United States Circuit Court of Appeals for the District of Columbia stayed the
effect of the final rule. The ultimate application of the final rule to SCE&G is
uncertain. 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 under what it believes is a fair
reading of both the prior regulation and the contested revised regulation. The
regulations also provide an exemption for an increase in emissions resulting
from increased hours of operation or production rate and from demand growth. The
current state of continued DOJ enforcement actions is the subject of speculation
industry-wide, but it is possible that the EPA will commence enforcement actions
against SCE&G, and the EPA has the authority to seek penalties at the rate of up
to $27,500 per day for each violation. The EPA also could seek installation of
BACT (or equivalent) at the two plants. SCE&G believes that any enforcement
actions relative to SCE&G's compliance with the CAA would be without merit.
However, if successful, such actions could have a material adverse effect on
SCE&G's financial condition, cash flows and results of operations. To comply
with current and anticipated state and federal regulations, SCE&G expects to
incur capital expenditures totaling approximately $129.9 million over the
2004-2008 period to retrofit existing facilities, with increased operation and
maintenance costs of approximately $1.2 million per year. To meet compliance
requirements for the years 2009 through 2013, SCE&G anticipates additional
capital expenditures of approximately $52.6 million.

         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 2004. 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 financial condition
and results of operations and cash flows of SCE&G.

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 2018 and
expects to be able to expand its storage capacity to accommodate the spent
nuclear fuel output for the life of the plant through 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.

        On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer
Station) filed suit in the Court of Federal Claims against the DOE for breach of
the above contract. The contract known as the Standard Contract for Disposal of
Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract),
required the federal government to accept and dispose of spent nuclear fuel and
high-level radioactive waste beginning not later than January 31, 1998, in
exchange for agreed payments fixed in the Standard Contract at particular
amounts. As of the date of filing, the federal government has accepted no spent
fuel from Summer Station or any other utility for transport and disposal, and
has indicated that it does not anticipate doing so until 2010, at the earliest.
As a consequence of the federal government's breach of contract, the plaintiffs
have incurred and will continue to incur substantial costs There are two
additional causes of action alleged as well - damages for breach of the implied
covenant of good faith and fair dealing and a takings claim demanding just
compensation for the taking of the plaintiffs' real property (necessitated by
the storage). This lawsuit is one of 48 similar lawsuits brought by nuclear
utilities as of January 29, 2004.

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
$10.9 million and $17.9 million at December 31, 2003 and 2002, 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 by the end of 2004, with certain monitoring and other
        activities continuing until 2007. As of December 31, 2003, SCE&G has
        spent approximately $19.7 million to remediate the Calhoun Park site,
        and expects to spend an additional $2.2 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. In addition, in March 2003
        SCE&G signed a consent agreement with DHEC related to a site formerly
        owned by SCE&G. The site contained residue material that was moved from
        an MGP. The removal action for this site has been completed. SCE&G
        anticipates that major remediation activities for the three owned sites
        will be completed before 2006. As of December 31, 2003, SCE&G has spent
        approximately $3.0 million related to these three sites, and expects to
        incur an additional $5.0 million.

REGULATORY 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. Material retail rate proceedings are
described in more detail in Note 2 to the consolidated financial statements.

       In conjunction with a January 2003 order, the SCPSC allowed SCE&G to
include all Jasper County generating station project expenditures as of December
31, 2002 and other construction work in progress expenditures as of June 30,
2002 in electric rate base. Once this generating station is complete, SCE&G may
seek to include the remaining project expenditures in electric rate base.
Construction expenditures for the Lake Murray Dam construction project, which
totaled approximately $169 million as of December 31, 2003, have not been
included in its electric rate base. When the Lake Murray project is completed in
2005, SCE&G will determine whether to seek inclusion of such expenditures in
electric rate base.

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, 2003 is approximately $2.5 million, and through December 31, 2003,
they have generated and passed through to SCE&G approximately $97.4 million in
such tax credits. At December 31, 2003 SCE&G has recorded on its balance sheet
$66.6 million deferred fuel tax benefits, which include partnership losses, net
of tax.

       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,
net of partnership losses and other expenses, 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 to the consolidated financial
statements.

       The IRS has completed and closed examinations of the Company's
consolidated federal income tax returns through the tax year ended in 2000, with
the exception of the Company's interest in the synthetic fuel partnership, S. C.
Coaltech No. 1 L.P. The IRS has notified the Company that it has begun the
process of closing this partnership examination with no changes being proposed,
and that a formal closing letter is forthcoming. The IRS audit report makes no
challenge to the declaration that the synthetic fuel facility was properly
placed in service, and takes no issue with evidence submitted demonstrating that
the facility produces a qualifying fuel.

        On October 29, 2003, the IRS issued Announcement 2003-70 stating that it
had completed a review of chemical change issues associated with tax credits
claimed under IRC Section 29 relating to the production and sale of synthetic
fuel. It further stated that it would resume the issuance of private letter
rulings (PLRs) concerning synthetic fuel credits consistent with the guidelines
regarding chemical change previously set forth in Revenue Procedures 2001-30 and
2001-34 and certain additional requirements related to sampling, testing and
recordkeeping procedures, even though the IRS has indicated that the level of
chemical change required under that guidance is not sufficient for IRC Section
29 purposes. The IRS also stated in the announcement that it would continue to
issue PLRs because it recognized that many taxpayers and their investors have
relied on its long standing ruling practice to make investments. In Announcement
2003-46 issued on June 27, 2003, the IRS had questioned the validity of certain
test procedures and results that had been presented to it by taxpayers with
interests in synfuel operations as evidence that the required significant
chemical change had occurred, and had initiated a review of these test
procedures and results which was completed as noted in Announcement 2003-70.

        Separately, the Permanent Subcommittee on Investigations of the
Government Affairs Committee of the United States Senate (Subcommittee) is
conducting an investigation of potential abuses of tax credits by producers of
synthetic fuel under IRC Section 29. The Subcommittee Chairman, in a memorandum
commencing the investigation, has stated that he anticipates the investigation
will focus on whether certain synthetic fuel producers are claiming tax credits
even though their product is not a qualified synthetic fuel under Section 29 and
IRS regulations. The memorandum also states that the investigation will address
whether certain corporations are engaging in transactions solely to take
advantage of unused Section 29 credits with no other business purpose, and the
IRS' efforts to curb abuses related to these credits.

        While the effect of these two developments is not clear, SCE&G is aware
that PLRs have been issued since October 29, 2003. SCE&G has not had any
communication with the Subcommittee staff, and with the imminent conclusion of
the IRS audit, SCE&G continues to believe that all of its synthetic fuel tax
credits have been properly claimed.

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. At December 31, 2003 SCE&G had capitalized
approximately $8.0 million related to the application process and expects to
capitalize an additional $1.0 million in 2004. SCE&G expects the extension to be
granted in mid-2004.

CRITICAL ACCOUNTING POLICIES

        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.

Utility Regulation

        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. 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 condition would be
materially affected. See Note 1 to the consolidated financial statements for a
description of SCE&G's regulatory assets and liabilities, including those
associated with SCE&G's environmental assessment program.

        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, 2003 SCE&G's net
investments in fossil/hydro and nuclear generation assets were approximately
$2,113 million and $563 million, respectively.


<PAGE>



Revenue Recognition and Unbilled Revenues

        Revenues related to the sale of energy are recorded when service is
rendered or when energy is delivered to customers. Because customers are billed
on cycles which vary based on the timing of the actual reading of their electric
and gas meters, SCE&G records estimates for unbilled revenues at the end of each
reporting period. Such unbilled revenue amounts reflect estimates of the amount
of energy delivered to 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. At December 31, 2003 and 2002, accounts
receivable included unbilled revenues of $50.0 million and $43.9 million,
respectively, compared to total revenues for 2003 and 2002 of $1.83 billion and
$1.68 billion, respectively.

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 expected write-offs. These estimates are based on,
among other things, comparisons of the relative age of accounts, assigned credit
ratings for commercial and industrial accounts, and consideration of actual
write-off history. SCE&G's Electric Distribution and Gas Distribution segments
have an established write-off histories and the regulated service areas that
enable them to reliably estimate their provisions 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. SCE&G expects to
receive a 20-year license extension for Summer Station that will significantly
impact the eventual cost of and funding for decommissioning. 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.

        Under SCE&G's method of funding decommissioning costs, 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.

Accounting for Pensions and Other Postretirement Benefits

        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 $6.8 million recorded in 2003 reflects
the use of a 6.5% discount rate and an assumed 9.25% long-term return on plan
assets. SCE&G believes that these assumptions were, and that the resulting
pension income amount was, reasonable. For purposes of comparison, using a
discount rate of 6.0% in 2003 would have lowered SCE&G's pension income
approximately $1.7 million. Had the assumed long-term return on assets been
reduced to 9.0% in 2003, SCE&G's pension income would have been reduced by
approximately $1.5 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 beginning of year discount rate of 6.5% as being within a
reasonable range of interest rates for obligations rated Aa by Moodys as of
January 1, 2003. This same discount rate was also selected for determination of
OPEB costs discussed below.

        The following information with respect to pension assets (and returns
thereon) 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 25 year cumulative actual returns of 10.8%, 12.0%
and 12.7%, respectively, all of 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 a target
asset allocation of 70% with equity managers and 30% with fixed income managers.
Management regularly reviews such allocations and periodically rebalances the
portfolio to the targeted allocation when considered appropriate.

        While investment performance in 2000-2002 and the recent 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 after 2008.

        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 6.5% and recorded a
net SFAS 106 cost of $13.1 million for 2003. Had the selected discount rate been
6.0%, the expense would have been approximately $0.4 million higher.

Asset Retirement Obligations

        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
operation. Because such obligation relates solely to SCE&G's regulated electric
operations, adoption of SFAS 143 had no impact on results of operations;
however, as of January 2003, SCE&G recorded an ARO of approximately $111
million, which exceeded the previously recorded reserve for nuclear plant
decommissioning of approximately $87 million. At December 31, 2003 such ARO
totaled approximately $118 million.

        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.


<PAGE>



OTHER MATTERS

Claims and Litigation

        For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS
and Note 10 to the consolidated financial statements.

 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

       All financial instruments held by SCE&G described below are held for
purposes other than trading.

       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, 2003                                                      Expected Maturity Date
Millions of dollars

Liabilities                         2004       2005       2006        2007        2008      Thereafter       Total     Fair Value
--------------------------------- ---------- --------- ----------- ----------- ----------- -------------- ------------ ------------

     Long-Term Debt:
<S>             <C>                 <C>       <C>        <C>          <C>         <C>         <C>           <C>          <C>
     Fixed Rate ($)                 135.5     185.5      166.2        35.5        35.5        1,670.4       2,228.6      2,162.1
     Average Interest Rate (%)       7.45      7.36        8.52       6.76        6.76            6.07         6.47

December 31, 2002                                                     Expected Maturity Date
Millions of dollars

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

     Long-Term Debt:
     Fixed Rate ($)                141.1     135.5      185.5       166.2         35.5       1,175.6       1,839.4      1,862.8
     Average Interest Rate (%)      6.37       7.45       7.36        8.52       6.76            6.81          7.03

       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.
</TABLE>


<PAGE>

<TABLE>
<CAPTION>



ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         INDEX TO CONSOLIDATED FINANCIAL
                        STATEMENTS AND SUPPLEMENTARY DATA
                                                                                                          Page

<S>                                                                                                        <C>
Independent Auditors' Report.............................................................................  104

Consolidated Financial Statements:

    Consolidated Balance Sheets as of December 31, 2003 and 2002.........................................   105

    Consolidated Statements of Income for years ended December 31, 2003, 2002 and 2001 ..................   107

    Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001 ..........   108

    Consolidated Statements of Capitalization as of December  31, 2003  and 2002.........................   109

   Consolidated Statements of Common Equity for the years ended December 31, 2003, 2002 and 2001 ........   110

    Notes to Consolidated Financial Statements...........................................................   111
</TABLE>


<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, 2003 and 2002 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, 2003. 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, 2003
and 2002 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.


s/Deloitte & Touche LLP
Columbia, South Carolina
February 26, 2004












<PAGE>
<TABLE>
<CAPTION>


SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS

------------------------------------------------------------------------------------- ---------------- -------------------
December 31, (Millions of dollars)                                                         2003               2002
------------------------------------------------------------------------------------- ---------------- -------------------
Assets
Utility Plant (Note 4):
<S>                                                                                       <C>                <C>
    Electric                                                                              $5,242             $4,934
    Gas                                                                                       456                439
    Common                                                                                    193               184
------------------------------------------------------------------------------------- ---------------- -------------------
        Total                                                                               5,891             5,557
    Accumulated depreciation and amortization                                              (1,801)           (1,687)
------------------------------------------------------------------------------------- ---------------- -------------------
        Total                                                                               4,090             3,870
    Construction work in progress                                                             884               604
    Nuclear fuel, net of accumulated amortization                                               42                38
------------------------------------------------------------------------------------- ---------------- -------------------
        Utility Plant, Net                                                                  5,016             4,512
------------------------------------------------------------------------------------- ---------------- -------------------

Nonutility Property and Investments, Net                                                        25                25
------------------------------------------------------------------------------------- ---------------- -------------------

Current Assets:
    Cash and temporary investments (Note 9)                                                     61                56
    Receivables, net                                                                          237                239
    Receivables - affiliated companies                                                          61                46
    Inventories (at average cost):
        Fuel                                                                                    30                48
        Materials and supplies                                                                  52                53
        Emission allowances                                                                      6                10
    Prepayments                                                                                 20                24
------------------------------------------------------------------------------------- ---------------- -------------------
        Total Current Assets                                                                  467                476
------------------------------------------------------------------------------------- ---------------- -------------------

Deferred Debits:
    Environmental                                                                               11                18
    Nuclear plant decommissioning                                                                -                87
    Assets held in trust, net - nuclear decommissioning                                        44                   -
    Pension asset, net  (Note 3)                                                              270                265
    Due from affiliates - pension and postretirement benefits (Note 3)                          20                18
    Other regulatory assets                                                                   326                267
    Other                                                                                     144                103
------------------------------------------------------------------------------------- ---------------- -------------------
        Total Deferred Debits                                                                 815                758
------------------------------------------------------------------------------------- ---------------- -------------------
            Total                                                                         $6,323             $5,771
===================================================================================== ================ ===================
</TABLE>








<PAGE>

<TABLE>
<CAPTION>

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE  SHEETS
------------------------------------------------------------------------------ -------------------- --------------------
December 31, (Millions of dollars)                                                    2003                 2002
------------------------------------------------------------------------------ -------------------- --------------------
Capitalization and Liabilities
Shareholders' Investment:
<S>                      <C>                                                         <C>                  <C>
    Common equity  (Note 6)                                                          $2,043               $1,966
    Preferred stock (Not subject to purchase or sinking funds) (Note 7)                  106                  106
------------------------------------------------------------------------------ -------------------- --------------------
        Total Shareholders' Investment                                                 2,149                2,072
Preferred Stock, net (Subject to purchase or sinking funds) (Note 7)                        9                    9
Company-Obligated Mandatorily Redeemable Preferred
    Securities of the Company's Subsidiary Trust, SCE&G Trust I, (Note 7)                   -                  50
Long-Term Debt, net  (Notes 4 & 9)                                                     1,943               1,534
------------------------------------------------------------------------------ -------------------- --------------------
    Total Capitalization                                                               4,101                3,665
------------------------------------------------------------------------------ -------------------- --------------------

Current Liabilities:
    Short-term borrowings  (Notes 5 & 9)                                                 140                  178
    Current portion of long-term debt  (Note 4)                                          138                  144
    Accounts payable                                                                     114                  124
    Accounts payable - affiliated companies                                                96                  77
    Customer deposits                                                                      24                  22
    Taxes accrued                                                                          97                  93
    Interest accrued                                                                       39                  31
    Dividends declared                                                                     38                  42
    Deferred income taxes, net  (Note 8)                                                    8                  12
    Other                                                                                  33                  39
------------------------------------------------------------------------------ -------------------- --------------------
    Total Current Liabilities                                                            727                  762
------------------------------------------------------------------------------ -------------------- --------------------

Deferred Credits:
    Deferred income taxes, net  (Note 8)                                                 665                  610
    Deferred investment tax credits (Note 8)                                             109                  108
    Reserve for nuclear plant decommissioning                                               -                   87
    Asset retirement obligation -  nuclear plant                                         118                     -
    Due to affiliates - pension and postretirement benefits (Note 3)                       15                   17
    Postretirement benefits  (Note 3)                                                    135                  131
    Regulatory liabilities                                                               398                  334
    Other                                                                                 55                    57
------------------------------------------------------------------------------ -------------------- --------------------
    Total Deferred Credits                                                             1,495                1,344
------------------------------------------------------------------------------ -------------------- --------------------

Commitments and Contingencies (Note 10)                                                     -                    -
------------------------------------------------------------------------------ -------------------- --------------------

           Total                                                                     $6,323               $5,771
============================================================================== ==================== ====================

   See Notes to Consolidated Financial Statements.
</TABLE>




<PAGE>

<TABLE>
<CAPTION>


SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME

-------------------------------------------------------------------------- ------------------- -------------- -----------------
For the Years Ended December 31,                                                  2003             2002             2001
-------------------------------------------------------------------------- ------------------- -------------- -----------------
(Millions of dollars)

Operating Revenues (Note 2):
<S>                                                                              <C>              <C>              <C>
    Electric                                                                     $1,472           $1,385           $1,374
    Gas                                                                              360              298              341
-------------------------------------------------------------------------- ------------------- -------------- -----------------
        Total Operating Revenues                                                  1,832            1,683            1,715
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Operating Expenses:
    Fuel used in electric generation                                                 273              257             224
    Purchased power (including affiliated purchases)                                164               152             234
    Gas purchased for resale                                                        269               211             252
    Other operation and maintenance                                                 393               366             315
    Depreciation and amortization                                                   188               171             163
    Other taxes                                                                     120               109               99
-------------------------------------------------------------------------- ------------------- -------------- -----------------
        Total Operating Expenses                                                  1,407             1,266           1,287
-------------------------------------------------------------------------- ------------------- -------------- -----------------
Operating Income                                                                    425               417             428
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Other Income:
    Other Income, Including Allowance for Equity Funds Used
       During Construction of $17, $20 and $13                                        35               36               26
    Gain on sale of assets                                                             1                 1               4
-------------------------------------------------------------------------- ------------------- -------------- -----------------
        Total Other Income                                                            36               37               30
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Income Before Interest Charges, Income Taxes and Preferred Stock                     461              454             458
Dividends
Interest Charges, Net of Allowance for Borrowed Funds Used
   During Construction of $8, $11 and $9                                             131              118             109
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Income Before Income Taxes and Preferred Stock Dividends                             330              336             349
Income Taxes (Note 8)                                                                108              113             123
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Income Before Preferred Stock Dividends                                              222              223             226
Dividend Requirement of Company - Obligated
   Mandatorily Redeemable Preferred Securities                                          2               4               4
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Net Income                                                                           220              219            222
Preferred Stock Cash Dividends (At stated rates)                                        7                7               7
-------------------------------------------------------------------------- ------------------- -------------- -----------------

Earnings Available for Common Shareholder                                           $213            $212            $215
========================================================================== =================== ============== =================
========================================================================== =================== ============== =================

See Notes to Consolidated Financial Statements.

</TABLE>



<PAGE>

<TABLE>
<CAPTION>

SOUTH CAROLINA ELECTRIC & GAS COMPANY
  CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)                     2003          2002          2001
----------------------------------------------------------------------- ------------ ------------- -------------

Cash Flows From Operating Activities:
<S>                                                                         <C>          <C>           <C>
Net income                                                                  $220         $219          $222
Adjustments to reconcile net income to net cash provided from
  operating activities:
    Depreciation and amortization                                            186          172           165
    Amortization of nuclear fuel                                               21           20           16
    Gain on sale of assets                                                     (1)          (1)           (4)
    Allowance for funds used during construction                             (25)          (31)         (22)
    Over (under) collection, fuel adjustment clause                           11            10            (3)
    Changes in certain assets and liabilities:
         (Increase) decrease in receivables                                  (13)          (46)           50
         (Increase) decrease inventories                                       23          (11)         (13)
         (Increase) decrease in prepayments                                     4          (18)           (1)
         (Increase) decrease in pension asset                                  (5)         (26)         (43)
         (Increase) decrease in other regulatory assets                       (35)           1            (2)
         Increase (decrease) in deferred income taxes, net                     51            11          27
         Increase (decrease) in other regulatory liabilities                   45           39           22
         Increase (decrease) in postretirement benefits obligations             4             9            9
         Increase (decrease) in accounts payable                                9           24           16
         Increase (decrease) in taxes accrued                                   4           13           29
         Increase (decrease) in interest accrued                                8            4             5
         Changes in other assets                                              (23)         (34)         (19)
         Changes in other liabilities                                          19           37          (17)
----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From Operating Activities                                  503          392          437
----------------------------------------------------------------------- ------------ ------------- -------------

Cash Flows From Investing Activities:
  Utility property additions and construction expenditures, net of AFC      (590)        (585)        (427)
  Nonutility property additions                                                 -           (3)          (2)
  Proceeds from sales of assets                                                 2            2            3
  Investments                                                                 (16)          (9)          (7)
----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Investing Activities                                      (604)        (595)        (433)
----------------------------------------------------------------------- ------------ ------------- -------------

Cash Flows From Financing Activities:
    Proceeds:
        Issuance of First Mortgage Bonds                                     743          295          149
        Issuance of Industrial Revenue Bonds                                    -           87          -
        Capital contributions from parent                                       9         157            33
    Repayments:
        Mortgage Bonds and Notes                                            (366)        (104)            -
        Pollution Control Facilities Revenue Bonds                            (11)         (62)           -
        Other long-term debt                                                    -           (3)          (5)
        Payment of deferred financing costs                                   (25)            -           -
        Retirement of preferred stock                                         (50)          (1)           -
    Dividend payments:
        Common stock                                                        (149)        (153)        (157)
        Preferred stock                                                        (7)          (7)          (7)
    Short-term borrowings, net                                               (38)           13          (23)
----------------------------------------------------------------------- ------------ ------------- -------------
----------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From (Used For) Financing Activities                       106          222           (10)
----------------------------------------------------------------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Temporary Investments                       5           19           (6)
Cash and Temporary Investments, January 1                                     56            37           43
----------------------------------------------------------------------- ------------ ------------- -------------
Cash and Temporary Investments, December 31                                  $61          $56          $37
======================================================================= ============ ============= =============

Supplemental Cash Flow Information:
   Cash paid for - Interest (net of capitalized interest of  $8, $11       $123          $114            $131
and $9)
                          - Income taxes                                      57            60           70

Noncash Investing and Financing Activities:
   Columbia Franchise Agreement                                                 -          $30            -

See Notes to Consolidated Financial Statements.

</TABLE>

<PAGE>


<TABLE>
<CAPTION>




SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
---------------------------------------------------------------------------------------- ------------- ------- ------------
December 31, (Millions of dollars)                                                           2003                 2002
---------------------------------------------------------------------------------------- ------------- ------- ------------

<S>                       <C>                                                               <C>                   <C>
Total Common Equity (Note 6)                                                                $2,043                $1,966
---------------------------------------------------------------------------------------- ------------- ------- ------------
Preferred Stock (Notes 7 & 9)
        $100 Par Value - Authorized 1,000,000 shares; available for issuance 0
          shares $50 Par Value - Authorized 618,804 shares; available for
          issuance 300,000 shares $25 Par Value - Authorized and available for
          issuance 2,000,000 shares

  Cumulative Preferred Stock (Not subject to purchase or sinking funds)
                                                    Shares
                                     Outstanding
                        Series            2003         2002        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 7)                    106                     106
---------------------------------------------------------------------------------------- ------------- ------- ------------

  Cumulative Preferred Stock (Subject to purchase and sinking funds), $50 Par

                                 Shares Outstanding
    Series                        2003         2002         Redemption Price
    ------                        ----         ----         ----------------
    4.50% & 4.60% (A)             17,034       18,849            $51.00                  1                    1
    4.60% (B)                     50,637       51,000             50.50                  3                    3
    5.125%                        64,000       65,000             51.00                  3                    3
    6.00%                        61,924       65,124              50.50                  3                    3
                              -  ------     - ------
Total                           193,595      199,973
                                =======      =======

---------------------------------------------------------------------------------------- ------------- -------- -----------
Total Preferred Stock  (Subject to purchase or sinking funds)                                  10                    10
Less:  Current portion, including sinking funds requirements                                   (1)                    (1)
---------------------------------------------------------------------------------------- ------------- -------- -----------
Total Preferred Stock, Net (Subject to purchase or sinking funds)                               9                      9
---------------------------------------------------------------------------------------- ------------- -------- -----------

Company-Obligated Mandatorily Redeemable Preferred Securities of Company's
   Subsidiary Trust, SCE&G Trust I (Note 7)                                                     -                    50
---------------------------------------------------------------------------------------- ------------- -------- -----------

Long-Term Debt (Notes 4 & 9):
                             Series Year of Maturity
First Mortgage Bonds:                               6 1/4%               2003                    -                   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
                                                    5.25%                2018                 250                       -
                                                    7 1/2%               2023                    -                   150
                                                    7 5/8%               2023                    -                   100
                                                    7 5/8%               2025                 100                    100
                                                    6.625%               2032                 300                    300
                                                    5.30%                2033                 300                       -
                                                    5.80%                2033                 200                       -
First and Refunding Mortgage Bonds                       9%              2006                 131                    131

Pollution Control Facilities Revenue Bonds:
   Orangeburg County Series 1994, due 2024 (5.70%)                                              30                    30
   Other                                                                                         -                    11
Industrial Revenue Bonds, due 2012-2032 (4.2%-5.5%)                                             90                    90
Franchise Agreements                                                                            15                    17
Other                                                                                           35                     2
--------------------------------------------------------------- ------------------------ ------------- -------- -----------
Total Long-Term Debt                                                                        2,101                 1,681
Less  -  Current maturities, including sinking fund                                           (138)                (144)
requirements
         -  Unamortized discount                                                               (20)                    (3)
--------------------------------------------------------------- ------------------------ ------------- -------- -----------
Total Long-Term Debt, Net                                                                   1,943                 1,534
--------------------------------------------------------------- ------------------------ ------------- -------- -----------
Total Capitalization                                                                         $4,101               $3,665
=============================================================== ======================== ============= ======== ===========

See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


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
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- ----------- ---------
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- ----------- ---------
<S>                 <C> <C>                     <C>            <C>          <C>           <C>         <C>         <C>        <C>
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
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- -----------
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- ----------- ---------
   Capital Contributions From Parent                                                          9                                    9
   Earnings Available for Common Shareholder                                                                       213          213
   Cash Dividends Declared                                                                                        (145)        (145)
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- ----------- ---------
---------------------------------------------- ------------- ---------- -------------- ------------ ---------- -----------
Balance at December 31, 2003                    40,296,147     $181          $395         $636        $(5)        $836       $2,043
============================================== ============= ========== ============== ============ ========== =========== =========
</TABLE>

(a) $4.50 par value, authorized 50 million shares

See Notes to Consolidated Financial Statements.


<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 predominantly in the generation
and sale of electricity to wholesale and retail customers in South Carolina and
in the purchase, sale and transportation of natural gas to retail customers in
South Carolina.

       The accompanying Consolidated Financial Statements reflect the accounts
of 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, 2003 and 2002, the
Company had approximately $39.5 million and $29.6 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, 2003 and
2002 the Company had approximately $10.7 million and $9.0 million, respectively,
payable to GENCO for unit power purchases. Such unit power purchases, which are
included in "Purchased power," amounted to approximately $100.0 million, $109.5
million and $95.8 million in 2003, 2002 and 2001, respectively.

       Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $1.8 million,
$0.4 million and $0.7 million in 2003, 2002 and 2001, respectively.

       The Company holds two equity-method investments in partnerships involved
in converting coal to synthetic fuel. The Company's receivables from these
affiliated companies totaled approximately $13.4 million and $8.5 million at
December 31, 2003 and 2002, respectively. The Company's payables to these
affiliated companies totaled approximately $12.2 million and $8.0 million at
December 31, 2003 and 2002, respectively.


<PAGE>


B.     Basis of Accounting

       The Company accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize
in their financial statements certain revenues and expenses in different time
periods than do enterprises that are not rate-regulated. As a result the Company
has recorded, as of December 31, 2003, approximately $337 million and $398
million of regulatory assets (including environmental) and liabilities,
respectively, as shown below.
<TABLE>
<CAPTION>

                                                                                              December 31,
Millions of dollars                                                                       2003            2002
------------------------------------------------------------------------------------- -------------- ---------------
------------------------------------------------------------------------------------- -------------- ---------------
<S>                                                                                       <C>              <C>
Accumulated deferred income taxes, net                                                    $101             $86
Under-collections  - electric fuel and gas cost adjustment clauses, net                      39             50
Deferred environmental remediation costs                                                     11             18
Asset retirement obligation - nuclear decommissioning                                       48                -
Deferred non-conventional fuel tax benefits, net                                            (67)           (40)
Storm damage reserve                                                                        (37)           (32)
Franchise agreements                                                                         62              65
Non-legal asset retirement obligations                                                     (238)          (225)
Other                                                                                        20              29
------------------------------------------------------------------------------------- -------------- ---------------
------------------------------------------------------------------------------------- -------------- ---------------
Total                                                                                      $(61)         $(49)
===================================================================================== ============== ===============
</TABLE>

       Accumulated deferred income tax liabilities arising from utility
operations that have not been included in customer rates are recorded as a
regulatory asset. Accumulated deferred income tax assets arising from deferred
investment tax credits are recorded as a regulatory liability.

       Under-collections - fuel adjustment clauses, net represent amounts
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 manufactured gas plant (MGP) sites currently or
formerly owned by the Company. Costs incurred at sites owned by the Company are
being recovered through rates. Such costs, totaling approximately $10.9 million,
are expected to be fully recovered by the end of 2009.

       Asset retirement obligation - nuclear decommissioning represents the
regulatory asset associated with the legal obligation to decommission and
dismantle V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143,
"Accounting for Asset Retirement Obligations." (See Note 1N).

       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 the Company's two partnerships involved in
converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax
credits generated from non-conventional fuel produced by the partnerships and
consumed by the Company and ultimately passed through to the Company, net of
partnership losses and other expenses, 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 period of
approximately ten years. The accumulated storm damage reserve can be applied to
offset actual incremental 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. These amounts are not earning a return, but are being amortized
through cost of service over approximately 15 years.

       Non-legal asset retirement obligations represent net collections through
depreciation rates of estimated costs to be incurred for the future retirement
of assets for which no legal retirement obligation exists. 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 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, liquidity or financial
position in the period the write-off would be recorded.

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 to accumulated depreciation.
The costs of repairs, replacements and renewals of items of property determined
to be less than a unit of property are charged to maintenance expense.

       The Company, operator of the V. C. Summer Nuclear Station (Summer
Station), and the South Carolina Public Service Authority (Santee Cooper) are
joint owners of Summer Station in the proportions of two-thirds and one-third,
respectively. The parties share the operating costs and energy output of the
plant in these proportions. Each party, however, provides its own financing.
Plant-in-service related to the Company's portion of Summer Station was
approximately $1,002.8 million and $962.4 million as of December 31, 2003 and
2002, respectively (including amounts related to ARO). Accumulated depreciation
associated with the Company's share of Summer Station was approximately $449.5
million and $417.9 million as of December 31, 2003 and 2002, respectively
(including amounts related to ARO). The Company's share of the direct expenses
associated with operating Summer Station is included in "Other operation and
maintenance" expenses and totaled approximately $74.7 million for the year ended
December 31, 2003.

       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 the Company begins accruing for each successive
outage immediately upon completion of the preceding outage. The Company accrued
approximately $0.5 million per month from January 2001 through June 2002 for the
outage period ended June 2002, and approximately $0.6 million per month from
July 2002 through December 2003 for the outage period ended December 2003. Total
outage costs for the fall 2003 outage was approximately $20.6 million, of which
the Company was responsible for approximately $13.9 million.

E. Allowance for Funds Used During Construction (AFC)

       AFC, a noncash item, reflects the period cost of capital devoted to plant
under construction. This accounting practice results in the inclusion of, as a
component of construction cost, the costs of debt and equity capital dedicated
to construction investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates for utility
services. The Company has calculated AFC using composite rates of 7.8%, 7.8% and
8.8% for 2003, 2002 and 2001, 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.


<PAGE>



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. Unbilled revenues totaled approximately $50
million and $43.9 million as of December 31, 2003 and 2002, 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 $26.7 million and $25.3 million
at December 31, 2003 and 2002, respectively, which amounts are included in other
regulatory assets.

       Customers subject to the gas cost adjustment clause are billed based on a
fixed cost of gas determined by the SCPSC during annual gas cost recovery
hearings. Any difference between actual gas costs and amounts contained in rates
is deferred and included when establishing gas costs during the next annual gas
cost recovery hearing. At December 31, 2003 and 2002 the Company had
undercollected through the gas cost recovery procedure approximately $11.9
million and $24.6 million, respectively, which amounts are also included in
other regulatory assets.

       The Company's gas rate schedules for residential, small commercial and
small industrial customers include a weather normalization adjustment which
minimizes fluctuations in gas revenues due to abnormal weather conditions.

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 3.02%, 2.93% and 2.98% for 2003, 2002 and 2001,
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 records its liability for
decommissioning cost in deferred credits.

       Under the Company's method of funding decommissioning costs, funds
collected through rates ($3.2 million in each of 2003, 2002 and 2001) 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.


       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 $1.5 million and $2.0
million at December 31, 2003 and 2002, 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 other regulatory assets.

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 the Company, in the form of capital contributions. In 2003
and 2002, capital contributions of approximately $8.5 million and $7 million,
respectively, were received by the Company 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 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.

        At the Company, site assessment and cleanup costs are deferred and
amortized with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $10.9
million and $17.9 million at December 31, 2003 and 2002, respectively. The
deferral includes the estimated costs associated with the matters discussed in
Note 10C.

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 5.)


<PAGE>



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

        The Company adopted SFAS 143, effective January 1, 2003. SFAS 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. As of December 31, 2002,
prior to the adoption of SFAS 143, the Company carried deferred debits and
deferred credits (each totaling approximately $87 million) related to the
decommissioning and dismantling of Summer Station and the funding thereof.
Effective January 1, 2003, in connection with the measurement of the ARO, the
amounts reflected within these regulatory assets and liabilities were
recharacterized.

        The following table presents such recharacterized amounts related to the
decommissioning obligation and the funding thereof as recorded in the
Consolidated Balance Sheet as of December 31, 2003, and the proforma amounts
that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been
adopted at the beginning of 2001.
<TABLE>
<CAPTION>

                                                                   December 31,      December 31,    December 31,
Millions of dollars                                                    2003              2002            2001
-------------------
                                                                      Actual           Proforma        Proforma
Assets:
<S>                                                                      <C>              <C>             <C>
Within electric plant                                                    $40              $40             $40
Within accumulated depreciation                                          (14)             (13)             (12)
Assets held in trust (net) - nuclear decommissioning                      44               39               35
Within other regulatory assets                                            48               45               42
                                                                 ------------------ --------------- ----------------
                                                                 ------------------ --------------- ----------------
     Total                                                             $118              $111            $105
                                                                 ================== =============== ================
                                                                 ================== =============== ================

Liabilities:
 Asset retirement obligation - nuclear plant decommissioning           $118              $111            $105
                                                                 ================== =============== ================
</TABLE>

       Proforma net income for periods prior to the adoption of SFAS 143 would
not differ from amounts actually recorded during these periods.

       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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. 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. There was no impact on the
Company's results of operations, cash flows or financial position from the
initial adoption of SFAS 145.


<PAGE>



       The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.

       SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133, " Accounting for Derivative Instruments and Hedging Activities".
SFAS 149 is effective for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 149.

       SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. SFAS
150 was effective for financial instruments entered into or modified after May
31, 2003, and otherwise was effective at the beginning of the first interim
period beginning after June 15, 2003. There was no impact on the Company's
results of operations, cash flows or financial position from the initial
adoption of SFAS 150.

       The Company adopted SFAS 132 (Revised 2003), Employers' Disclosure about
Pension and Other Postretirement Benefits," which is effective for financial
statements issued for fiscal years ending December 15, 2003. This statement
increased existing disclosure requirements by requiring more details about
assets, obligations, cash flows and net periodic benefit cost of defined benefit
pension plans and other defined benefit postretirement plans. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of this statement.

O.     Reclassifications

       Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2003.

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.


<PAGE>



2. RATE AND OTHER REGULATORY MATTERS

       Electric

        In January 2003 the SCPSC granted the Company a composite increase in
retail electric rates of approximately 5.8% 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, based
on the level of revenues and operating expenses, 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 additional approval of the SCPSC. Any unused portion
of the $36 million in any given year may be carried forward for possible use in
the following year.

        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 was effective for service
rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order
approving the Company's request to maintain the fuel cost component of rates at
1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the
prudence of the Company's purchasing practice and recognized the efficiency of
SCE&G's electric generating plants; however, it deferred action on the recovery
of certain purchased power costs pending the resolution of the appeal of the
SCPSC's May 2002 order discussed below.

        In December 2002 the SCPSC approved the Company's request to capitalize
the cost of fuel consumed in the production of test power for the gas turbines
installed at Urquhart 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 approved 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 reflected 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. The Consumer Advocate of South Carolina
appealed to the South Carolina Circuit Court (Circuit Court) the portion of the
SCPSC's order related to the recovery of certain purchased power costs. The
appeal is still pending.

        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, 2003 and 2002 was as follows:

 Rate Per Therm  Effective Date            Rate Per Therm Effective Date

   $.728       January-February 2003          $.596     January-October 2002
   $.928       March-October 2003             $.728     November-December 2002
   $.877       November-December 2003

        The SCPSC allows the Company 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 2003, as a result of
the annual review, the SCPSC approved the Company's request to reduce the
billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is
intended to provide for the recovery, prior to the end of the year 2009, of the
balance remaining at December 31, 2003 of $10.9 million.

3. EMPLOYEE BENEFIT PLANS

Pension and Other Postretirement Benefit Plans

        The Company participates in SCANA's noncontributory defined benefit
pension plan, which covers substantially all permanent employees. The Company's
policy has been to fund the plan to the extent permitted by 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 credited
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.

        In addition to pension benefits, the Company provides certain unfunded
postretirement health care and life insurance benefits to active and retired
employees. Retirees share in a portion of their medical care cost. The Company
provides life insurance benefits to retirees at no charge. The costs of
postretirement benefits other than pensions are accrued during the years the
employees render the services necessary to be eligible for the applicable
benefits.

         The measurement date used to determine pension and other postretirement
benefit obligations is December 31. Information regarding the benefit
obligations and the funding thereof is presented below.

Changes in Benefit Obligations

        Data related to the changes in the projected benefit obligation for
retirement benefits and the accumulated benefit obligation for other
postretirement benefits are presented below.

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

Millions of dollars                  2003    2002       2003       2002
                                     ----    ----       ----       ----

Benefit obligation, January 1      $595.6  $530.8      $183.4     $166.7
Service cost                          9.5     9.1           2.7        3.1
Interest cost                        36.7    39.8         11.4       12.4
Plan participants' contributions        -                   0.8       0.9
                                                -
Actuarial loss                        7.6    50.6           4.3      10.8
Benefits paid                      (29.5)  (34.7)        (14.2)     (10.5)
                                   ------  -----      -- ------  -  -----
Benefit obligation, December 31    $619.9  $595.6      $188.4     $183.4
                                   ======  ======      ======     ======

        The accumulated benefit obligation for retirement benefits at the end of
2003 and 2002 was $589.8 million and $570.0 million, respectively. These
accumulated retirement benefit obligations differ from the projected retirement
benefit obligations above in that they reflect no assumptions about future
compensation levels.




<PAGE>

<TABLE>
<CAPTION>


        Significant assumptions used to determine the above benefit obligations
are as follows:

                                                                                       2003        2002
<S>                                                                                    <C>         <C>
  Annual discount rate used to determine benefit obligations                           6.00%       6.50%
  Assumed annual rate of future salary increases for projected benefit obligation      4.00%       4.00%
</TABLE>

        A 9.5% annual rate of increase in the per capita cost of covered health
care benefits was assumed for 2004. The rate was assumed to decrease gradually
to 5.0% for 2011 and remain at that level thereafter. The effects of a
one-percentage-point increase or decrease on accumulated other postretirement
benefit obligation for health care benefits are as follows:

                                                   1%                 1%
  Millions of dollars                           Increase           Decrease
                                               --------------- -----------------

  Effect on postretirement benefit obligation     $0.9              $(1.1)

        The Medicare Prescription Drug, Improvement and Modernization Act of
2003 (the Act) was signed December 8, 2003 to make additional voluntary
prescription drug benefits available through Medicare. The Company has elected
not to recognize the effects of the Act in these financial statements. The
Company will be evaluating the implications of the Act during 2004 and recognize
expected financial effects as prescribed by accounting standards in effect for
subsequent reporting periods.

Changes in Plan Assets

                                               Retirement Benefits
                                          -----------------------------------
Millions of dollars                         2003                2002
                                            ----                ----

Fair value of plan assets, January 1       $666.9              $831.6
Actual return on plan assets                 150.3              (130.0)
Benefits paid                                (29.5)              (34.7)
                                             ------        --    -----
Fair value of plan assets, December 31     $787.7              $666.9
                                           ======              ======

At the end of 2003 and 2002, the fair value of plan assets for the pension plan
exceeded both the projected benefit obligation and the accumulated benefit
obligation discussed above. Since the accumulated benefit obligation is less
than the fair value of plan assets, there is no adjustment to other
comprehensive income.
<TABLE>
<CAPTION>

Funded Status of Plans

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

<S>                                                                   <C>        <C>             <C>         <C>
Millions of dollars                                                   2003       2002            2003        2002
                                                                      ----       ----            ----        ----

Funded status, December 31                                           $167.8      $71.3         $(188.4)    $(183.4)
Unrecognized actuarial (gain) loss                                      23.1     107.5             45.0        42.2
Unrecognized prior service cost                                         76.8       83.1              2.9        3.9
Unrecognized net transition obligation                                   2.3         3.1            5.9          6.6
                                                                   ---------   ---------      ---------   ----------
Net asset (liability) recognized in consolidated balance sheet       $270.0     $265.0         $(134.6)    $(130.7)
                                                                     ======     ======         ========    ========
</TABLE>

In connection with the joint ownership of Summer Station, as of December 31,
2003 and 2002 the Company recorded within deferred credits a $9.3 million and
$9.1 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, 2003 and 2002, the Company
also recorded a $6.5 million and $6.4 million receivable, respectively, from
Santee Cooper, representing an estimate of its portion of the unfunded net
postretirement benefit obligation.

Expected Cash Flows

        The total benefits expected to be paid from the pension plan or from the
Company's assets for the pension and other postretirement benefits plans,
respectively, are as follows:

Expected Benefit Payments
Millions of dollars        Pension Benefits    Other Postretirement Benefits*
-------------------        ----------------    ------------------------------
2004                             $39.2                      $13.4
2005                               41.0                       13.7
2006                               42.8                       14.0
2007                               43.3                       14.3
2008                               48.0                       14.5
2009 - 2013                      266.0                        75.2
* Net of participant contributions

Net Periodic Cost

        As allowed by SFAS 87 and SFAS 106, 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 (Income)

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

Millions of dollars                                  2003      2002        2001          2003         2002          2001
                                                     ----      ----        ----          ----         ----          ----

<S>                                                  <C>         <C>        <C>          <C>           <C>          <C>
Service cost                                         $9.5        $9.0       $7.9         $2.7          $3.1         $3.0
Interest cost                                        36.7        39.8       38.5         11.4          12.4          12.1
Expected return on assets                           (59.9)      (77.6)     (83.5)          n/a          n/a           n/a
Prior service cost amortization                       6.3         6.3        5.8           0.9          0.9           0.9
Actuarial (gain) loss                                 1.6                  (12.8)          1.5           1.1          0.7
                                      (4.1)
Transition Amount  Amortization                       0.8         0.8        0.8           0.8           0.8          0.8
Amount Attributable to Company Affiliates            (1.8)        0.3         2.2         (4.2)         (4.7)        (3.1)
                                                   -------   --------   ----- ---      --------     --  -----      -------
Net periodic benefit (income) cost                  $(6.8)    $(25.5)    $(41.1)         $13.1        $13.6        $14.4
                                                    ======    =======    ======          =====        =====        =====

Significant Assumptions Used in Determining Net Periodic Cost

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

                                                       2003       2002       2001           2003         2002       2001
                                                       ----       ----       ----           ----         ----       ----

Discount rate                                         6.50%      7.50%      8.00%          6.50%        7.50%      8.00%
Expected return on plan assets                        9.25%      9.50%      9.50%            n/a          n/a        n/a
Rate of compensation increase                         4.00%      4.00%      4.00%          4.00%        4.00%      4.00%
Health care cost trend rate                             n/a        n/a        n/a         10.00%        8.50%      7.50%
Ultimate health care cost trend rate                    n/a        n/a        n/a          5.00%        5.00%      5.50%
Year achieved                                           n/a        n/a        n/a           2011         2009       2005
Measurement date                                      Jan 1      Jan 1      Jan 1          Jan 1        Jan 1      Jan 1
</TABLE>

The effect of a one-percentage-point increase or decrease in the assumed health
care cost trend rate on total service and interest cost is less than $100,000.

Pension Plan Contributions

        While the investment performance over the 2000-2002 period and the
recent decline in discount rates have significantly reduced the level of pension
income, the pension trust has been and remains adequately funded. No
contributions have been required since 1997, and the Company does not anticipate
making contributions to the funded pension plan in 2004. As such, these declines
in pension income have had no impact on the Company's cash flows.

Pension Plan Asset Allocations

        The Company's pension plan asset allocation at December 31, 2003 and
2002 and the target allocations for 2004 are as follows:


                                   Target           Percentage of Plan Assets
Asset Category                   Allocation              At December 31
                                 ----------              --------------
                                                     2003              2002
                                                     ----              ----
Equity Securities                    70%              71%              73%
Debt Securities                      30%              29%              27%


        The assets of the pension plan are invested in accordance with the
objectives of (1) fully funding the actuarial accrued liability for the pension
plan (Plan), (2) maximizing return within reasonable and prudent levels of risk
in order to minimize contributions, and (3) maintaining sufficient liquidity to
meet benefits payment obligations on a timely basis. These objectives have been
based on a ten-year investment horizon, so that interim fluctuations should be
viewed with appropriate perspective. The pension plan operates with several risk
and control procedures including a review of liabilities, investment objectives,
investment managers and performance expectations. Transactions involving certain
types of investments are prohibited. Equity securities held by the pension plan
during the above periods did not include SCANA Corporation common stock.

        In developing the expected long-term rate of return assumptions,
management evaluates the pension plan's historical cumulative actual returns
over several periods, which have all been in excess of related broad indices,
and management anticipates that the pension 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 a target asset allocation of 70% with equity
managers and 30% with fixed income managers. Management regularly reviews such
allocations and periodically rebalances the portfolio to the targeted allocation
when considered appropriate.

4. LONG-TERM DEBT

       The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2004 through 2008 are summarized as follows:

------------------ ----------------- ------------------ -----------------
      Year              Amount             Year              Amount
------------------ ----------------- ------------------ -----------------
                         (Millions of dollars)

      2004               $138              2007               $38
      2005                188              2008                 38
      2006                172
------------------ ----------------- ------------------ -----------------

       Approximately $35.5 million of the long-term debt maturing in 2004 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, 2003 the Company had
not yet borrowed under the agreement.


       On October 15, 2002 the Company 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.

       The Company has a three-year revolving line of credit totaling $75.0
million, expiring in 2005, that provides a source of liquidity in addition to
other lines of credit.

       Substantially all utility plant is pledged as collateral in connection
with long-term debt.

5. SHORT-TERM BORROWINGS

       Details of lines of credit and short-term borrowings at December 31, 2003
and 2002, are as follows:

Millions of dollars                           2003             2002
--------------------------------------------------------- ---------------

Lines of credit (total and unused)
   Committed                                  $400             $300
   Uncommitted (1)                               78                 -
Short-term borrowings outstanding
      Commercial paper (270 or fewer days)   $140.1           $177.7
      Weighted average interest rate             1.15%            1.40%

(1) Comprised of a $78 million line that either the Company or SCANA may use.

       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 14, 2004. 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 $45.7 million and $50.1
million at December 31, 2003 and 2002, respectively, at weighted average
interest rates of 1.15% and 1.38%, respectively.

       The Company's commercial paper outstanding totaled $94.4 million and
$127.6 million at December 31, 2003 and 2002, respectively, at weighted average
interest rates of 1.15% and 1.40%, respectively.

6. 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, 2003 approximately $44 million of retained earnings were
restricted by this requirement as to payment of cash dividends on common stock.


<PAGE>



7. PREFERRED STOCK

       Retirements under sinking fund requirements are at par values. The
aggregate of the annual amounts of purchase fund or sinking fund requirements
for preferred stock for the years 2004 through 2008 is $2.7 million. The call
premium of the respective series of preferred stock in no case exceeds the
amount of the annual dividend.

       Changes in "Total Preferred Stock (Subject to purchase or sinking funds)"
during 2003, 2002 and 2001 are summarized as follows:

                                       Number of Shares  Millions of Dollars
-------------------------------------------------------- -----------------------
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
   Shares Redeemed  - $50 par value           (6,378)               (0.3)
-------------------------------------------------------- -----------------------
Balance at December 31, 2003                193,595                 $9.7
======================================================== =======================

       On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned
subsidiary of SCE&G, issued $50 million of 7.55% Trust Preferred Securities,
Series A. On May 21, 2003 SCE&G effected the redemption of the Trust Preferred
Securities.

8. INCOME TAXES
<TABLE>
<CAPTION>

       Total income tax expense attributable to income (before cumulative effect
of accounting change) for 2003, 2002 and 2001 is as follows:

Millions of dollars                                                      2003            2002              2001
---------------------------------------------------------------- ----------------- ----------------- -----------------
Current taxes:
<S>                                                                   <C>                 <C>              <C>
      Federal                                                         $23.2               $60.4            $83.8
      State                                                              8.3                 8.3             10.2
---------------------------------------------------------------- ----------------- ----------------- -----------------
---------------------------------------------------------------- ----------------- ----------------- -----------------
            Total current taxes                                         31.5                68.7             94.0
---------------------------------------------------------------- ----------------- ----------------- -----------------
---------------------------------------------------------------- ----------------- ----------------- -----------------
Deferred taxes, net:
      Federal                                                           40.2                12.6              8.7
      State                                                              0.7                 2.0              1.6
---------------------------------------------------------------- ----------------- ----------------- -----------------
---------------------------------------------------------------- ----------------- ----------------- -----------------
            Total deferred taxes                                        40.9               14.6              10.3
---------------------------------------------------------------- ----------------- ----------------- -----------------
---------------------------------------------------------------- ----------------- ----------------- -----------------
Investment tax credits:
      Deferred - State                                                   5.0                5.0               5.0
      Amortization of amounts deferred - State                          (1.8)              (1.7)             (1.5)
      Amortization of amounts deferred - Federal                        (3.2)              (3.2)             (3.2)
---------------------------------------------------------------- ----------------- ----------------- -----------------
            Total investment tax credits                                    -               0.1               0.3
---------------------------------------------------------------- ----------------- ----------------- -----------------
Non-conventional fuel tax credits:
      Deferred - Federal                                                 35.7              29.8              18.7
---------------------------------------------------------------- ----------------- ----------------- -----------------
            Total income tax expense                                  $108.1            $113.2            $123.3
================================================================ ================= ================= =================
</TABLE>



<PAGE>


<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                                                    2003              2002
                                                                                                           2001
---------------------------------------------------------------- ----------------- ----------------- ------------------

<S>                                                                   <C>               <C>                <C>
Income before cumulative effect of accounting change                  $213.1            $212.3             $214.5
Income tax expense                                                     108.1              113.1             123.3
Preferred stock dividends                                                 9.1              11.2              11.2
---------------------------------------------------------------- ----------------- ----------------- ------------------
      Total pre-tax income                                            $330.3            $336.6            $349.0
================================================================ ================= ================= ==================
================================================================ ================= ================= ==================

Income taxes on above at statutory federal income tax rate            $115.6            $117.8            $122.2
Increases (decreases) attributed to:
   State income taxes (less federal income tax effect)                    7.9                8.8               9.9
    Allowance for equity funds using during construction                 (5.9)              (6.9)             (4.7)
   Amortization of federal investment tax credits                        (3.2)              (3.2)             (3.2)
   Other differences, net                                                (6.3)              (3.3)             (0.9)
---------------------------------------------------------------- ----------------- ----------------- ------------------
---------------------------------------------------------------- ----------------- ----------------- ------------------
        Total income tax expense                                      $108.1            $113.2            $123.3
================================================================ ================= ================= ==================
</TABLE>

<TABLE>
<CAPTION>

       The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $673.1 million at December 31, 2003 and
$622.5 million at December 31, 2002 (see Note 1I), are as follows:

Millions of dollars                                                                     2003              2002
---------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax assets:
<S>                                                                                     <C>               <C>
   Nondeductible reserves                                                               $63.0             $59.1
   Unamortized investment tax credits                                                     55.3             56.1
   Deferred compensation                                                                  22.1             21.0
   Other                                                                                 15.3              12.7
---------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax assets                                                       155.7             148.9
---------------------------------------------------------------------------------- ---------------- ------------------

Deferred tax liabilities:
   Property, plant and equipment                                                         702.6            644.9
   Pension plan benefit income                                                            94.4              93.0
   Deferred fuel costs                                                                    14.8             19.1
   Other                                                                                  17.0             14.4
---------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax liabilities                                                   828.8            771.4
---------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability                                                             $673.1              $622.5
================================================================================== ================ ==================
</TABLE>

       The Internal Revenue Service has completed and closed examinations of the
Company's consolidated federal income tax returns through the tax year ended in
2000, with the exception of the Company's interest in the synthetic fuel
partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it
is in the process of closing this partnership examination with no changes being
proposed, and that a formal closing letter is forthcoming. The IRS makes no
challenge to the declaration that the synthetic fuel facility was properly
placed in service, and takes no issue with the evidence submitted demonstrating
that the facility produces a qualifying fuel. The Company continues to believe
that all of its synthetic fuel tax credits have been properly claimed.


<PAGE>



9. FINANCIAL INSTRUMENTS

       The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2003 and 2002 are as follows:
<TABLE>
<CAPTION>

  Millions of dollars                                                2003                     2002
  ---------------------------------------------------------- ---------------------- --------------------------
                                                                          Estimated                Estimated
                                                              Carrying      Fair       Carrying       Fair
                                                               Amount       Value       Amount       Value
  ---------------------------------------------------------- ----------- ------------ ------------ -----------
  Assets:
<S>                                                              <C>         <C>          <C>         <C>
    Cash and temporary cash investments                          $61.4       $61.4        $56.1       $56.1
     Investments                                                    5.7         5.7          5.5         5.5
  Liabilities:
    Short-term borrowings                                        140.1       140.1        177.7        177.7
    Long-term debt                                            2,081.8      2,192.7      1,677.8     1,878.5
    Preferred stock (subject to purchase or sinking funds)          9.7         8.8         10.0          8.6
  ---------------------------------------------------------- ----------- ------------ ------------ -----------
</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,
             certificates of deposits, 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 considered.

o            In anticipation of the issuance of debt, the Company also uses
             interest rate lock or similar agreements to manage interest rate
             risk. Payments received or made upon termination of such agreements
             are recorded within other deferred debits on the balance sheet and
             are amortized to interest expense over the term of the underlying
             debt. In connection with the issuance of First Mortgage Bonds in
             May 2003, the Company paid approximately $11.9 million upon the
             termination of a treasury lock agreement. In connection with the
             issuance of First Mortgage Bonds on December 2003, the Company paid
             approximately $3.5 million upon the termination of a forward
             starting interest rate swap.

10. COMMITMENTS AND CONTINGENCIES:

A.      Lake Murray Dam Reinforcement

        In October 1999 FERC mandated that the Company reinforce its Lake Murray
Dam in order to comply with new federal safety standards. 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, 2003 totaled approximately $169 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 $10.9 billion. Each
reactor licensee is currently liable for up to $100.6 million per reactor owned
for each nuclear incident occurring at any reactor in the United States,
provided that not more than $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 $67.1 million per incident,
but not more than $6.7 million per year.

        Congress failed to renew the Price-Anderson Indemnification Act when the
Act expired in 2003. The Act is expected to renew with only modest changes in
2004. The delayed renewal has no impact on the Company due to the
"grandfathered" status of existing licensees that are covered under the expired
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 retrospective assessments under certain conditions to cover
insurer's losses. Based on the current annual premium, the Company's portion of
the retrospective premium assessment would not exceed $15.8 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 deferred and
amortized with recovery provided through rates. Deferred amounts, net of amounts
previously recovered through rates and insurance settlements, totaled $10.9
million at December 31, 2003. 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 by the
end of 2004, with certain monitoring and other activities continuing until 2007.
As of December 31, 2003, the Company has spent approximately $19.7 million to
remediate the Calhoun Park site, and expects to spend an additional $2.2
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. In addition, in March 2003 the Company signed a consent
agreement with DHEC related to a site formerly owned by the Company. The site
contained residue material that was moved from a MGP site. The removal action
for this site has been completed. The Company anticipates that major remediation
activities for the three owned sites will be completed before 2006. As of
December 31, 2003, the Company has spent approximately $3.0 million related to
these three sites, and expects to spend an additional $5.0 million.

D.     Franchise Agreements

       See Notes 1B and 4 for a discussion of the electric and gas franchise
agreements between the Company and the cities of Columbia and Charleston.


<PAGE>



E.     Claims and Litigation

       On August 21, 2003, the Company was served as a co-defendant in a
purported class action lawsuit styled as Collins v. Duke Energy Corporation,
Progress Energy Services Company, and South Carolina Electric & Gas Company, in
South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit.
The plaintiffs are seeking damages for the alleged improper use of electric
transmission easements but have not asserted a dollar amount for their claims.
Specifically, the plaintiffs contend that the licensing of attachments on
electric utility poles, towers and other facilities to non-utility third parties
or telecommunication companies for other than the electric utilities' internal
use along the electric transmission line right-of-way constitutes a trespass.
The Company is confident of the propriety of its actions and intends to mount a
vigorous defense. 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.

       A complaint was filed on October 22, 2003 against the Company by the
State of South Carolina alleging that the Company violates the Unfair Trade
Practices Act by charging municipal franchise fees to some customers residing
outside a municipality's limits. The complaint also alleges that the Company
failed to obey, observe, or comply with the lawful order of the SCPSC by
charging franchise fees to those not residing in a municipality. The complaint
seeks restitution to all affected customers and penalties up to $5,000 for each
separate violation. The Company is confident of the reasonableness of its
actions and intends to mount a vigorous defense. The allegations contained in
the complaint are the subject of a similar lawsuit that was filed and served on
the Company, for which a Motion to Dismiss is pending. The allegations are also
the subject of a purported class action lawsuit filed on or about December 12,
2003 against Duke Energy Corporation, Progress Energy Services Company and the
Company. The Company further believes that the resolution of these actions will
not have a material adverse impact on its results of operations, cash flows or
financial condition. In addition, the Company filed a petition with the SCPSC on
October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests
that the SCPSC exercise its jurisdiction to investigate the operation of the
municipal franchise fee collection requirements applicable to the Company's
electric and gas service, to approve the Company's efforts to correct any past
franchise fee billing errors, to adopt improvements in the system which will
reduce such errors in the future, and to adopt any regulation which the SCPSC
deems just and proper to regulate the franchise fee collection process.

       The Company is also engaged in various other claims and litigation
incidental to their business operations which management anticipates will be
resolved without material loss to the Company.

F.      Operating Lease Commitments

       The Company is obligated under various operating leases with respect to
office space, furniture and equipment. Leases expire at various dates through
2009. Rent expense totaled approximately $9.9 million, $9.3 million and $9.0
million in 2003, 2002 and 2001, respectively. Future minimum rental payments
under such leases are as follows:

                                     Millions of dollars
                        2004              $13.0
                        2005                11.5
                        2006                10.9
                        2007                  9.4
                        2008                  8.8
                        Thereafter            8.2
                                           ---------
                                               $61.8

        At December 31, 2003 minimum rentals to be received under noncancelable
subleases with remaining lease terms in excess of one year totaled approximately
$10 million.


<PAGE>



G.      Purchase Commitments

        Purchase commitments for coal supply, construction projects and other
commitments are as follows:

                                    Millions of dollars
                                    -------------------
                        2004            $297.8
                        2005              250.6
                        2006              110.9
                        2007                  5.3
                        2008                  2.8
                                  Thereafter        12.6
                                                -----------
                                        $680.0

        In addition, included in purchase commitments are customary purchase
orders under which the Company has the option to utilize certain vendors without
the obligation to do so. The Company may terminate such commitments without
penalty.

11. SEGMENT OF BUSINESS INFORMATION

        The Company's reportable segments are Electric Operations and Gas
Distribution. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies. The Company records
intersegment sales and transfers of electricity and gas based on rates
established by the appropriate regulatory authority. Non-regulated sales and
transfers are recorded at current market prices.

         Electric Operations is comprised of the electric portion of the Company
and Fuel Company and is primarily engaged in the generation, transmission, and
distribution of electricity. The Company's electric service territory extends
into 24 counties covering more than 15,000 square miles in the central,
southern, and southwestern portions of South Carolina. Sales of electricity to
industrial, commercial, and residential customers are regulated by the SCPSC and
by FERC. Fuel Company acquires, owns, and provides financing for the fuel and
emission allowances required for the operation of the Company's generation
facilities.

         Gas Distribution, comprised of the local distribution operations of the
Company, is engaged in the purchase and sale, primarily at retail, of natural
gas. The Company's operations extend to 33 counties in South Carolina covering
approximately 22,000 square miles.

         The Company's reportable segments share a similar regulatory
environment and, in some cases, overlapping service areas. However, Electric
Operations' 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
              2003                Operations    Distribution        Other         Eliminations          Total
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------

<S>                                 <C>             <C>                                                <C>
Customer Revenue                    $1,472          $360               -                  -            $1,832
Intersegment Revenue                       -            1              -               $(1)                   -
Operating Income (Loss)                 412            15              -                 (2)               425
Interest Expense                           1             -           $2                128                 131
Depreciation & Amortization             175            13              -                  -                188
Segment Assets                       4,518            283              -               1,522            6,323
Expenditures for Assets                 592            20              -                (22)               590
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------



<PAGE>



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

Customer Revenue                    $1,385          $298               -                  -            $1,683
Intersegment Revenue                     -              2              -              $(2)                    -
Operating Income (Loss)                 403            15              -                 (1)               417
Interest Expense                           2          n/a            $4                 112                118
Depreciation & Amortization             159            12              -                   -               171
Segment Assets                       4,296           315               -               1,160             5,771
Expenditures for Assets                 594            19              -                (25)               588
--------------------------------- ------------ --------------- ---------------- ----------------- ------------------

Millions of dollars
---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
                                     Electric        Gas             All          Adjustments/      Consolidated
              2001                  Operations   Distribution       Other         Eliminations          Total
---------------------------------- ------------- ------------- ----------------- ---------------- ------------------

Customer Revenue                      $1,374         $341               -                  -           $1,715
Intersegment Revenue                       -             -              -               -                     -
Operating Income (Loss)                   405          26               -                $(3)              428
Interest Expense                            3         n/a             $4                102                109
Depreciation & Amortization              151           12               -                  -               163
Segment Assets                         3,664         268                3             1,027              4,962
Expenditures for Assets                  409           16               -                 4                429
---------------------------------- ------------- ------------- ----------------- ---------------- ------------------
</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, net for its segments. Therefore, the Company does not
allocate 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's deferred tax assets are netted with deferred tax
liabilities for reporting purposes.

         The Consolidated Financial Statements report operating revenues which
are comprised of the reportable segments. Revenues from non-reportable segments
are included in Other Income. Therefore, the adjustments to total revenue remove
revenues from non-reportable segments. Segment assets include utility plant, net
for all reportable segments. As a result, adjustments to assets include
non-utility plant and non-fixed assets for the segments. Interest Expense is
adjusted to include the totals from the Company that are not allocated to the
segments and to eliminate inter-segment charges.

12. QUARTERLY FINANCIAL DATA (UNAUDITED)

Millions of dollars
-----------------------------------------------------------------------------
                           First     Second      Third     Fourth
2003                      Quarter   Quarter     Quarter    Quarter   Annual
-----------------------------------------------------------------------------

Total operating revenues    $478      $422       $484       $448     $1,832
Operating income               99        88        150         88        425
Net income                     47        40         88         45        220
-----------------------------------------------------------------------------

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

Total operating revenues    $411      $403       $472       $397     $1,683
Operating income               99        79       155          84        417
Net income                     52        40         86         41        219
-----------------------------------------------------------------------------


















                             PUBLIC SERVICE COMPANY
                         OF NORTH CAROLINA, INCORPORATED








Item 7.   Management's Narrative Analysis of  Results of Operations......  132

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.....  136

Item 8.   Financial Statements and Supplementary Data....................  137






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 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, including competition from alternate fuels in industrial
interruptible markets, (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 assets and the 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, 2003 and 2002 was as
follows:

Millions of dollars                                     2003            2002
------------------------------------------------------------------ -------------

Net income (loss)                                      $30.9          $(207.0)
Less:  Cumulative effect of accounting change                -          (229.6)
------------------------------------------------------------------ -------------
Income before cumulative effect of accounting change   $30.9             $22.6
================================================================== =============

         Income before the cumulative effect of accounting change increased
approximately $8.3 million, primarily due to increased margin of $12.7 million,
and other income of $4.6 million, and reduced interest expense of $0.7 million,
which was partially offset by higher operating expenses of $4.1 million and
higher income taxes of $5.6 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 effective January 1,
2002. The charge is presented on the Consolidated Statements of Operations as
the Cumulative Effect of Accounting Change. SFAS 142 requires that an impairment
evaluation be performed annually and at the same time each year. PSNC Energy
performed an annual evaluation as of January 1, 2003 and no further impairment
was indicated.

         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.


<PAGE>



         PSNC Energy's Board of Directors has authorized the following
distributions/dividends on common stock held by SCANA during 2003:

Declaration Date   Distribution Amount Quarter Ended        Payment Date

February 20, 2003   $4.5 million       March 31, 2003       April 1, 2003
May 1, 2003         $4.5 million       June 30, 2003        July 1, 2003
July 31, 2003       $4.0 million       September 30, 2003   October 1, 2003
November 7, 2003    $4.0 million       December 31, 2003    January 1, 2004

Gas Distribution

         Gas distribution sales margins for 2003 and 2002 were as follows:

Millions of dollars     2003            2002            Change         % Change
----------------------------------- -------------- ----------------- -----------

Operating revenues     $508.9          $355.7           $153.2           43.1%
Less:  Cost of gas      (330.4)         (189.9)         (140.5)         (74.0%)
----------------------------------- -------------- -----------------
Gross margin           $178.5          $165.8            $12.7            7.7%
=================================== ============== ================= ===========

         Gas distribution sales margin for the year ended December 31, 2003
increased $6.8 million due to higher natural gas usage attributable to colder
weather, $4.2 million due to customer growth and $0.7 million due to higher
other operating revenues. The margin increase was partially offset by $1.2
million due to lower industrial natural gas usage arising from competition with
alternate fuels. In addition to these changes affecting margins, revenues and
costs also increased in 2003 because of higher commodity natural gas prices.

Operation and Maintenance Expenses

         The $4.8 million increase in operation and maintenance expenses from
2002 is primarily due to increased bad debt expense of $2.4 million related to
higher write-offs and increased gas costs. Also contributing to the increase are
higher outside labor and general business expenses of $1 million and the impact
of reduced pension income of $0.9 million.

Other Income

         Other income increased $4.6 million for the year ended December 31,
2003 as compared to the same period in 2002 primarily due to increased income of
$1.6 million from secondary market activities, such as off-system gas sales and
pipeline capacity release, and increased interest income of $0.9 million
primarily from amounts under-collected from customers through the operation of
the Rider D mechanism. This mechanism allows PSNC Energy to recover all
prudently incurred gas costs. In addition, merchandising and jobbing income
increased $2.4 million primarily due to increased interest income of $0.8
million, a reduced provision for bad debt of $0.7 million, and increased
appliance sales of $0.5 million.

Interest Expense

         Interest expense decreased $0.7 million over 2002 due to reduced
long-term debt and lower 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 2004 construction budget is approximately $51 million, compared to
actual construction expenditures for 2003 of $48.5 million.

         PSNC Energy's contractual cash obligations as of December 31, 2003 are
summarized as follows:
<TABLE>
<CAPTION>

                          Contractual Cash Obligations

                                                         Less than                                            After
December 31, 2003                          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)                       $583           $82               $66               $43            $392
Operating leases                                  1            1                 -                 -               -
Purchase obligations                            30             4               26                  -               -
Other commercial commitments                   856          266               227               116             247
--------------------------------------- ------------- ---------------- ------------------ ---------------- -------------
--------------------------------------- ------------- ---------------- ------------------ ---------------- -------------
           Total                           $1,470          $353              $319              $159            $639
--------------------------------------- ------------- ---------------- ------------------ ---------------- -------------
</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. Because these contracts relate
to regulated gas businesses, their effects on gas costs are reflected in gas
rates.

        Included in purchase obligations are customary purchase orders under
which PSNC Energy has the option to utilize certain vendors without the
obligation to do so. PSNC Energy may terminate such purchase obligations without
penalty.

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.

       At December 31, 2003 PSNC Energy had available the following securities
to meet its liquidity needs:

                                                                (Millions)
       Lines of credit:
          364-day                                                  $125
       Short-term borrowings outstanding:
          Commercial paper (270 or fewer days)                      $55
          Weighted average interest rate                            1.17%

       PSNC Energy is party to two interest rate swap agreements which allow it
to pay variable rates and receive fixed rates on a combined notional amount of
$33.1 million at December 31, 2003. (See Note 7 to the consolidated financial
statements.) PSNC Energy utilizes no off-balance sheet financings or similar
arrangements other than incidental operating leases, generally for office
furniture and equipment.

Competition

        Natural gas competes with electricity, propane and heating oil to serve
the heating and, to a lesser extent, the other household energy needs of
residential and small commercial customers. This competition is generally based
on price and convenience. Large commercial and industrial customers often have
the ability to switch from natural gas to an alternate fuel, such as propane or
fuel oil. Natural gas competes with these alternate fuels based on price. As a
result, any significant disparity between supply and demand, either of natural
gas or of alternate fuels, and due either to production or delivery disruptions
or other factors, will affect the price and impact PSNC Energy's ability to
retain large commercial and industrial customers on a monthly basis.

        The NCUC has approved a rate structure that allows PSNC Energy to
negotiate reduced rates in order to match the cost of alternate fuels to large
commercial and industrial customers and recover the lost margin from other
classes of customers. PSNC Energy anticipates that the need to negotiate reduced
rates with these customers will continue.

Critical Accounting Policies

        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, 2003 PSNC Energy had recorded approximately $16.5 million and $86.0 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities. 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 other deferred
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 other deferred 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, 2003
and 2002, accounts receivable included unbilled revenues of $38.3 million and
$27.7 million, respectively, compared to total revenues for 2003 and 2002 of
$508.9 million and $355.7 million, respectively.

        SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and
Other Intangible Assets," SCANA Corporation performed an initial valuation
analysis of its investment in PSNC Energy using an independent appraisal. 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. PSNC Energy
performed an annual evaluation as of January 1, 2003 and no further impairment
was indicated.


<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, 2003                                                    Expected Maturity Date
  Millions of dollars

  Liabilities                           2004     2005       2006       2007       2008     Thereafter    Total    Fair Value
  ------------------------------------ ------- ---------- ---------- ---------- ---------- ----------- ---------- ------------

  Long-Term Debt:
<S>          <C>                         <C>       <C>        <C>        <C>        <C>      <C>         <C>         <C>
  Fixed Rate ($)                         7.5       3.2        3.2        3.2        3.2      262.8       283.1       321.1
  Average Fixed Interest Rate (%)       9.47     8.75       8.75       8.75       8.75          7.0        7.1
  Interest Rate Swaps:
  Pay Variable/Receive Fixed ($)        7.5        3.2        3.2        3.2        3.2       12.8       33.1           1.9
  Average Pay Interest Rate (%)         4.7      4.36       4.36       4.36       4.36        4.36         4.7
  Average Receive Interest Rate (%)     8.9      8.75       8.75       8.75       8.75        8.75         8.9

  December 31, 2002                                                    Expected Maturity Date
  Millions of dollars

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

  Long-Term Debt:
  Fixed Rate ($)                          7.5      7.5       3.2         3.2        3.2      266.0       290.6       325.4
  Average Fixed Interest Rate (%)        9.47    9.47       8.75       8.75       8.75          7.0        7.2
  Interest Rate Swaps:
  Pay Variable/Receive Fixed ($)          7.5      7.5       3.2        3.2        3.2         16.0       40.6          2.9
  Average Pay Interest Rate (%)           5.2      5.2      4.59       4.59       4.59         4.59         5.2
  Average Receive Interest Rate (%)       9.0      9.0      8.75       8.75       8.75         8.75         9.0
</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 provision for the recovery of actual gas costs incurred. PSNC Energy
records transaction fees and any realized gains or losses from derivatives
acquired as part of its hedging program in deferred accounts as regulatory
assets and liabilities for the over or under recovery of gas costs. In an
October 2003 order, in connection with PSNC Energy's 2003 annual prudency
review, the NCUC determined that PSNC Energy's gas costs, including all hedging
transactions, were reasonably and prudently incurred during the 12-month review
period ended March 31, 2003.


<PAGE>

<TABLE>
<CAPTION>


ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                                      INDEX TO CONSOLIDATED FINANCIAL
                                                     STATEMENTS AND SUPPLEMENTARY DATA
                                                                                                          Page

<S>                                                                                                        <C>
    Independent  Auditors' Reports........................................................................ 138

    Consolidated Financial Statements:

    Consolidated Balance Sheets as of December 31, 2003 and 2002.......................................... 139

       Consolidated Statements of Operations for the Years Ended
              December 31, 2003, 2002 and 2001............................................................ 140

       Consolidated Statements of Cash Flows for the Years  Ended
             December 31, 2003, 2002 and 2001............................................................. 141

       Consolidated Statements of Capitalization as of December 31, 2003 and 2002......................... 142

       Consolidated Statements of Comprehensive Income (Loss) and Changes in
             Common Equity for the Years Ended December 31, 2003, 2002 and 2001........................... 142

       Notes to Consolidated Financial Statements......................................................... 143


</TABLE>







<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, 2003 and 2002, 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, 2003. 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, 2003
and 2002, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2003 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 1 to the consolidated financial statements, the Company
adopted Statement of Financial Standards No. 142, "Goodwill and Other
Intangibles," effective January 1, 2002.


s/Deloitte & Touche LLP
Columbia, South Carolina
February 26, 2004


<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS

---------------------------------------------------------------------------- ------------------------ --------------------------
December  31, (Millions of dollars)                                                   2003                      2002
---------------------------------------------------------------------------- ------------------------ --------------------------

Assets

<S>                                                                                     <C>                     <C>
Gas Utility Plant                                                                       $923                    $895
   Accumulated depreciation                                                             (256)                    (248)
   Acquisition adjustment, net of accumulated amortization                               210                      210
---------------------------------------------------------------------------- ------------------------ --------------------------
     Gas Utility Plant, Net                                                              877                      857
---------------------------------------------------------------------------- ------------------------ --------------------------

Nonutility Property and Investments, Net                                                   28                      28
---------------------------------------------------------------------------- ------------------------ --------------------------

Current Assets:
   Cash and temporary investments                                                          18                        1
   Restricted cash and temporary investments                                                7                        7
   Receivables, net of allowance for uncollectible accounts
     of $2 and $2                                                                        115                        97
   Receivables - affiliated companies                                                       5                      14
   Inventories (at average cost):
      Stored gas                                                                          56                        38
      Materials and supplies                                                                5                        6
   Prepayments                                                                              2                        1
   Deferred income taxes, net (Note 6)                                                      3                        3
---------------------------------------------------------------------------- ------------------------ --------------------------
     Total Current Assets                                                                211                      167
---------------------------------------------------------------------------- ------------------------ --------------------------

Deferred Debits:
   Due from affiliate-pension asset   (Note 3)                                             13                      14
   Regulatory assets                                                                       17                      20
   Other                                                                                    6                        7
----------------------------------------------------------------------------                          --------------------------
                                                                             ------------------------
     Total Deferred Debits                                                                 36                      41
----------------------------------------------------------------------------                          --------------------------
                                                                             ------------------------
        Total                                                                        $1,152                       $1,093
============================================================================ ======================== ==========================
============================================================================                          ==========================

Capitalization and Liabilities
Capitalization:
   Common equity                                                                        $502                    $487
   Long-term debt, net (Notes 4 & 7)                                                     278                      286
                                                                             ------------------------
---------------------------------------------------------------------------- ------------------------ --------------------------
     Total Capitalization                                                                780                      773
---------------------------------------------------------------------------- ------------------------ --------------------------
                                                                             ------------------------

Current Liabilities:
   Short-term borrowings (Notes 5 & 7)                                                     55                       31
   Current portion of long-term debt (Note 4)                                               8                        8
   Accounts payable                                                                        48                       44
   Accounts payable - affiliated companies                                                  2                        7
   Customer deposits                                                                       7                        6
   Taxes accrued                                                                           10                        5
   Interest accrued                                                                         6                        6
   Distributions/dividends declared                                                         4                        5
   Other                                                                                   15                       16
---------------------------------------------------------------------------- ------------------------ --------------------------
                                                                             ------------------------
     Total Current Liabilities                                                           155                      128
---------------------------------------------------------------------------- ------------------------ --------------------------
                                                                             ------------------------

Deferred Credits:
   Deferred income taxes, net (Note 6)                                                     96                       91
   Deferred investment tax credits (Note 6)                                                 2                         2
   Due to affiliate-postretirement benefits (Note 3)                                       17                       16
   Regulatory liabilities                                                                  86                        71
   Other                                                                                   16                       12
---------------------------------------------------------------------------- ------------------------ --------------------------
     Total Deferred Credits                                                              217                       192
---------------------------------------------------------------------------- ------------------------ --------------------------

Commitments and Contingencies (Note 8)                                                      -                         -
---------------------------------------------------------------------------- ------------------------ --------------------------

        Total                                                                        $1,152                        $1,093
============================================================================ ======================== ==========================


See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>

<TABLE>
<CAPTION>



PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS

------------------------------------------------------------------------ --------------- --------------- -------------
For the Years Ended December 31,                                              2003            2002           2001
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------
(Millions of dollars)

<S>                                                                           <C>             <C>            <C>
Operating Revenues                                                            $509            $356           $453
Cost of Gas                                                                    330             190            286
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------
      Gross Margin                                                             179             166            167
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Operating Expenses:
   Operation and maintenance                                                     75              70            69
   Depreciation and amortization                                                 34              35            43
   Other taxes                                                                    7               7              6
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------
      Total Operating Expenses                                                 116             112            118
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Operating Income                                                                 63             54             49
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Other Income, Including Allowance for Equity Funds
   Used During Construction of $1, $1 and $0                                      8               3              6

Interest Charges, Net of Allowance for Borrowed Funds
   Used During Construction of $0, $0 and $1                                     21             21             22
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Income Before Income Taxes and
  Cumulative Effect of Accounting Change                                         50             36             33

Income Taxes (Note 6)                                                            19             13             18
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Income Before Cumulative Effect of Accounting Change                             31             23            15

Cumulative Effect of Accounting Change, net of taxes                              -          (230)              -
------------------------------------------------------------------------ --------------- --------------- -------------
------------------------------------------------------------------------ --------------- --------------- -------------

Net Income (Loss)                                                               $31          $(207)          $15
======================================================================== =============== =============== =============

See Notes to Consolidated Financial Statements.
</TABLE>




<PAGE>
<TABLE>

<CAPTION>

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS

--------------------------------------------------------------------------- ------------- ---------------- ---------------
For the Years Ended December 31,                                                2003           2002             2001
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------
Millions of  dollars

Cash Flows From Operating Activities:
<S>                                                                             <C>           <C>               <C>
   Net income (loss)                                                            $31           $(207)            $15
   Adjustments to reconcile net income to net cash provided
       from operating activities:
         Cumulative effect of accounting change, net of taxes                      -             230               -
         Depreciation and amortization                                           36               37              46
         Allowance for funds used during construction                             (1)              (1)            (1)
         Excess distributions (undistributed earnings
           of equity method investee)                                              -                -              3
         Over (under) collection, gas cost adjustment clause                      11             (24)             23
         Change in certain assets and liabilities:
           (Increase) decrease in receivables, net                                (18)           (31)             58
           (Increase) decrease in inventories                                    (17)             11             (15)
           (Increase) decrease in regulatory assets                                -               1               1
           (Increase) decrease in regulatory liabilities                           -               1                -
           Increase (decrease) in accounts payable and advances                   (1)              1             (68)
           Increase (decrease) in deferred income taxes, net                       5               2               3
         Changes in other assets                                                   -              (6)              6
         Changes in other liabilities                                              9               4               8
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------
Net Cash Provided From Operating Activities                                       55              18             79
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------

Cash Flows From Investing Activities:
   Construction expenditures, net of AFC                                        (47)            (47)            (74)
   Proceeds on sale of assets                                                     12               -               1
   Nonutility and other                                                          (1)              (1)              -
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------
Net Cash Used For Investing Activities                                          (36)             (48)           (73)
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------

Cash Flows From Financing Activities:
   Proceeds from issuance of medium-term notes                                     -               -            148
   Capital contributions from parent, net                                          1               -               3
   Retirement of long-term debt                                                   (8)             (4)             (4)
   Distributions/dividend payments                                               (19)            (14)            (18)
   Short-term borrowings, net                                                    24               31              (125)
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------
Net Cash Provided From (Used For) Financing Activities                            (2)             13               4
=========================================================================== ============= ================ ===============
=========================================================================== ============= ================ ===============

Net Increase (Decrease) in Cash and Temporary Investments                         17             (17)             10
Cash and Temporary Investments, January 1                                          1              18               8
--------------------------------------------------------------------------- ------------- ---------------- ---------------
--------------------------------------------------------------------------- ------------- ---------------- ---------------
Cash and Temporary Investments, December 31                                     $18               $1                $18
=========================================================================== ============= ================ ===============
=========================================================================== ============= ================ ===============

Supplemental Cash Flow Information:
Cash paid for:    Interest (net of capitalized interest of $1, $1 and $1)       $19             $19                 $16
                          Income taxes                                             8              14              12

The implementation of SFAS 142 resulted in a $230 million non-cash write-down of
the acquisition adjustment in 2002. (See Note 1G.)

See Notes to Consolidated Financial Statements.

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CAPITALIZATION

------------------------------------------------------------------------------------ -------------- ---------------
December 31, (Millions of dollars)                                                       2003            2002
------------------------------------------------------------------------------------ -------------- ---------------

Common Equity:
<S>                                                                                     <C>                 <C>
   Common stock, $1 par, 1,000 shares authorized and issued in 2003 and 2002                  -              -
  Capital in excess of par value                                                         $670             $686
  Accumulated other comprehensive loss                                                       (1)            (1)
  Retained earnings (deficit)                                                             (167)         (198)
                                                                                     --------------
------------------------------------------------------------------------------------ -------------- ---------------
Total Common Equity                                                                        502           487
------------------------------------------------------------------------------------ -------------- ---------------
                                                                                     --------------

Long-term Debt:
  Senior debentures (unsecured):
     10% due 2004 (1)                                                                        5              9
     8.75%  due 2012 (1)                                                                    29             32
     6.99% due 2026                                                                         50             50
     7.45% due 2026                                                                         50             50
  Medium-term notes:
    6.625% due 2011                                                                        150           150
  Fair Market Value of Interest Rate Swaps                                                    2             3
------------------------------------------------------------------------------------ -------------- ---------------
------------------------------------------------------------------------------------ -------------- ---------------
  Total Long-Term Debt                                                                     286           294
  Less - Current maturities                                                                 (8)            (8)
------------------------------------------------------------------------------------ -------------- ---------------
------------------------------------------------------------------------------------ -------------- ---------------
  Total Long-Term Debt, Net                                                                278           286
------------------------------------------------------------------------------------ -------------- ---------------
------------------------------------------------------------------------------------ -------------- ---------------
  Total Capitalization                                                                   $780             $773
==================================================================================== ============== ===============

(1) Fixed rate debt hedged by variable interest rate swap

See Notes to Consolidated Financial Statements.
</TABLE>

<TABLE>
<CAPTION>

PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
AND CHANGES IN COMMON EQUITY

                                                                                      Accumulated
                                                                        Capital          Other         Retained       Total
                                                     Common Stock      in Excess     Comprehensive     Earnings      Common
Millions of dollars                            Shares       Amount       of Par           Loss        (Deficit)      Equity
------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
<S>                 <C> <C>                                               <C>                              <C>        <C>
Balance at December 31, 2000                                     -        $703                             $9         $712
                                               1,000
  Capital Contributions From Parent                                           3                                            3
  Net Income/Comprehensive 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
------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
                                                                                                                  --------------
  Capital Contributions from Parent, net                                      1                                            1
  Net Income/Comprehensive Income                                                                           31           31
  Cash Distributions/Dividends Declared                                     (17)                                        (17)
------------------------------------------- ------------- ----------- ------------- ----------------- ----------- --------------
------------------------------------------- ------------- ----------- ------------- ----------------- -----------
Balance at December 31, 2003                      1,000       -           $670            $(1)          $(167)        $502
=========================================== ============= =========== ============= ================= =========== ==============
</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

         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. 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 certain 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, 2003, approximately $17 million and $86
million of regulatory assets and liabilities, respectively, as shown below.

                                                                  December 31,
Millions of dollars                                          2003        2002
----------------------------------------------------------------------- --------
----------------------------------------------------------------------- --------

Excess deferred income taxes                                    -         $(1)
Under-(over-) collections - gas cost adjustment clause, net  $(1)          10
Deferred environmental remediation costs                        9            9
Non-legal asset retirement obligations                        (77)        (70)
----------------------------------------------------------------------- --------
Total                                                       $(69)        $(52)
======================================================================= ========

         Excess deferred income taxes represent deferred income taxes recorded
in prior years at a rate higher than the current statutory rate. Pursuant to a
North Carolina Utilities Commission (NCUC) order, the Company was required to
refund these amounts to customers through a rate decrement.

         Under-(over-) collections - gas cost adjustment clause, net represents
amounts under- or over-collected from customers pursuant to the Company's Rider
D mechanism approved by the NCUC. This mechanism allows the Company to recover
all prudently incurred gas costs. (See Note 1F.)

         Deferred environmental remediation costs represents costs associated
with the assessment and cleanup of manufactured gas plant (MGP) sites currently
or formerly owned by the Company. A portion of the costs incurred are being
recovered through rates. Approximately $2.2 million in costs have been incurred
and deferred that are not currently being recovered through gas rates (see Note
8). Management believes these costs and the remaining costs of approximately
$7.0 million will be recoverable.

         Non-legal asset retirement obligations represent net collections
through depreciation rates of estimated costs to be incurred for the future
retirement of assets for which no legal retirement obligation exists.

<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, liquidity or financial position in the period the write-off would be
recorded.

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 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 12.7%, 12.1%
and 7.0% for the years ended December 31, 2003, 2002 and 2001, 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 $38.3 million and $27.7 million as of December 31, 2003 and 2002,
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 a manner authorized by the NCUC. Pursuant to
the operation of Rider D, at December 31, 2003 the Company had overcollected
from customers approximately $1.0 million, net. The Company had undercollected
from customers approximately $10.2 million, net at December 31, 2002.

         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 4.1%, 4.3% and 4.1% for 2003, 2002 and 2001,
respectively.

         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. The Company
has no other significant intangible assets subject to amortization as provided
in SFAS 142.

         If the Company had ceased amortization of the $466 million acquisition
adjustment during all periods presented in the consolidated statements of
operations, net income (loss) would have been as follows:

  (Millions of dollars)                    2003         2002        2001
                                           ----         ----        ----

  Net Income (Loss) as Reported             $31        $(207)        $15
  Amortization of Acquisition Adjustment       -             -        13
                                          --   -     ------  -    --  --
  Net Income (Loss) as Adjusted             $31        $(207)        $28
                                            ===        ======        ===

         In connection with 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 approximately $230 million. The resulting impairment
charge is reflected on the statement of operations as the cumulative effect of
an accounting change. SFAS 142 requires that an impairment evaluation be
performed annually and at the same time each year. The Company performed an
annual evaluation as of January 1, 2003 and no further impairment was indicated.

H.       Income Taxes

         The Company is included in the consolidated federal income tax return
of SCANA Corporation. Under a joint consolidated income tax allocation
agreement, each subsidiary's current and deferred tax expense is computed on a
stand-alone basis. Deferred tax assets and liabilities are recorded for the tax
effects of all significant temporary differences between the book basis and tax
basis of assets and liabilities at currently enacted 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, certain 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 2003 and 2002 net capital contributions of $1.2 million and
$0.6 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 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.


<PAGE>


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.

         The Company receives refunds from its pipeline transporters. Pursuant
to an order of the NCUC, these funds are segregated from the Company's general
funds and may only 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.

L.       New Accounting Standards

         The Company adopted SFAS 143, "Accounting for Asset Retirement
Obligations," 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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
effective January 1, 2003. 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. There was no impact on the Company's
results of operations, cash flows or financial position from the initial
adoption of SFAS 145.

        The Company adopted SFAS 146, "Accounting for Costs Associated with Exit
or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or
financial position from the initial adoption of SFAS 146.

        SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133, " Accounting for Derivative Instruments and Hedging Activities".
SFAS 149 is effective for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. There was no
impact on the Company's results of operations, cash flows or financial position
from the initial adoption of SFAS 149.


<PAGE>



        SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. It
requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). SFAS 150 was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period beginning after June
15, 2003. There was no impact on the Company's results of operations, cash flows
or financial position from the initial adoption of SFAS 150.

M.       Related Party Transactions

         The Company has related party transactions with its equity method
investees. The Company records as cost of gas the storage and transportation
costs charged by these investees. These costs totaled approximately $16.5
million, $17.0 million and $17.2 million in 2003, 2002 and 2001, respectively.
The Company owed these investees approximately $1.3 million at December 31, 2003
and $1.4 million at December 31, 2002 and 2001.

         At December 31, 2003 an affiliate owed the Company $0.9 million for
natural gas and transportation services. Additionally, the Company owed an
affiliate $0.2 million related to billing and collection services for the sale
of energy-related products and service contracts.

         Effective January 1, 2001 PSNC Production Corporation (PSNC Production)
and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc.
(SEMI), a subsidiary of SCANA, for $4.4 million, which approximated their net
book value. During the fourth quarter 2003, SEMI paid the Company $9.4 million
for an outstanding receivable due from PSNC Production. The receivable was for
cash advanced by the Company to PSNC Production prior to the sale.

N.       Reclassifications

         Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2003.

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. 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 delivered cost of gas in its deferred accounts for
subsequent rate consideration. The NCUC reviews the Company's gas purchasing
practices annually.


<PAGE>



       The Company's benchmark cost of gas in effect during the years ended
December 2003 and 2002 was as follows:

Rate Per Therm  Effective Date           Rate Per Therm   Effective Date

    $.460       January-February 2003         $.300       January 2002
    $.595       March 2003                    $.215       February-June 2002
    $.725       April-November 2003           $.350       July-October 2002
    $.600       December 2003                 $.410       November-December 2002

        In October 2003, in connection with the Company's 2003 Annual Prudence
Review, the NCUC determined that the Company's gas costs, including all hedging
transactions, were reasonable and prudently incurred during the 12-month review
period ended March 31, 2003. The NCUC also authorized new rate decrements to
refund over-collections of certain gas costs included in the Company's deferred
accounts, effective November 1, 2003.

        A state expansion fund, established by the North Carolina General
Assembly 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 million. The Madison County and Jackson County
portions of the project were completed in 2002, and the Swain County portion is
expected to be completed in the spring of 2004. Through December 31, 2003
approximately $27.4 million had been spent on this project.

        In December 1999 the NCUC issued an order approving SCANA's acquisition
of the Company. As specified in the order, the Company 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.

3. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS

Employee Benefit Plans

            The Company participates 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 applicable federal income tax regulations as determined by an
independent actuary. The Company also participates 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.

        For the years ended December 31, 2003 and 2002, the Company's net
periodic benefit income (loss) was approximately $(1.2) million and $0.2
million, respectively, for the pension plan, and net periodic benefit cost was
approximately $2.9 million and $2.3 million, respectively, for the
postretirement plan.



<PAGE>


4. LONG-TERM DEBT

       Long-term debt maturities are $7.5 million for 2004 and $3.2 million for
each of 2005 through 2008.

5. SHORT-TERM BORROWINGS

  Millions of dollars                            2003             2002
  ---------------------------------------------------------- ---------------

  Lines of credit (total and unused)            $125.0           $125.0
  Short-term borrowings outstanding:
        Commercial paper (270 or fewer days)     $55.2            $31.1
        Weighted average interest rate              1.17%            1.42%

       The Company pays fees to banks as compensation for committed lines of
credit.

6. INCOME TAXES
<TABLE>
<CAPTION>

       Total income tax expense attributable to income (before cumulative
effects of accounting changes) for 2003, 2002 and 2001 is as follows:

  Millions of dollars                                    2003              2002             2001
  ------------------------------------------------- ---------------- ----------------- ---------------

  Current taxes:
<S>                                                      <C>                <C>             <C>
        Federal                                          $12.1              $9.7            $14.0
        State                                               3.3              2.0               3.0
  ------------------------------------------------- ---------------- ----------------- ---------------
  ------------------------------------------------- ---------------- ----------------- ---------------
              Total current taxes                         15.4              11.7              17.0
  ------------------------------------------------- ---------------- ----------------- ---------------
  ------------------------------------------------- ---------------- ----------------- ---------------
  Deferred taxes, net:
        Federal                                             4.0              1.7               1.2
        State                                                 -              0.3               0.3
  ------------------------------------------------- ---------------- ----------------- ---------------
  ------------------------------------------------- ---------------- ----------------- ---------------
              Total deferred taxes                          4.0              2.0               1.5
  ------------------------------------------------- ---------------- ----------------- ---------------
  ------------------------------------------------- ---------------- ----------------- ---------------
  Investment tax credits:
        Amortization of amounts deferred - Federal         (0.3)            (0.3)             (0.3)
  ------------------------------------------------- ---------------- ----------------- ---------------
  ------------------------------------------------- ---------------- ----------------- ---------------
              Total investment tax credits                 (0.3)            (0.3)             (0.3)
  ------------------------------------------------- ---------------- ----------------- ---------------
              Total income tax expense                   $19.1            $13.4              $18.2
  ================================================= ================ ================= ===============
</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                                                   2003         2002         2001
---------------------------------------------------------------------------------------------------------

<S>                                                                   <C>          <C>         <C>
Income before cumulative effect of accounting change                  $30.9        $22.6       $14.8
Income tax expense                                                     19.1         13.4        18.2
---------------------------------------------------------------------------------------------------------
      Total pre-tax income                                            $50.0        $36.0       $33.0
=========================================================================================================
=========================================================================================================

Income taxes on above at statutory federal income tax rate            $17.5        $12.6       $11.6
Increases (decreases) attributed to:
   State income taxes (less federal income tax effect)                   2.2          1.6         2.1
    Non-deductible book amortization of acquisition adjustment                          -         4.7
   Amortization of federal investment tax credits                       (0.3)        (0.3)       (0.3)
   Other differences, net                                               (0.3)        (0.5)        0.1
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
        Total income tax expense                                      $19.1        $13.4       $18.2
=========================================================================================================
</TABLE>

The tax effects of significant temporary differences comprising the Company's
net deferred tax liability of $92.9 million at December 31, 2003 and $87.7
million at December 31, 2002 (see Note 1H) are as follows:
<TABLE>
<CAPTION>

--------------------------------------------------------------------------------- ---------------- ------------------
Million of dollars                                                                     2003              2002
--------------------------------------------------------------------------------- ---------------- ------------------

Deferred tax assets:
<S>                                                                                      <C>              <C>
    Nondeductible reserves                                                               $1.0             $1.0
   Other                                                                                  4.4               4.1
--------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax assets                                                         5.4               5.1
--------------------------------------------------------------------------------- ---------------- ------------------

Deferred tax liabilities:
   Property, plant and equipment                                                         92.3              88.1
   Other                                                                                  6.0               4.7
--------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax liabilities                                                  98.3               92.8
--------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability                                                             $92.9             $87.7
================================================================================= ================ ==================
</TABLE>

7. FINANCIAL INSTRUMENTS

       The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2003 and 2002 are as follows:
<TABLE>
<CAPTION>

Millions of dollars                                2003                          2002
-------------------------------------------------------------------- ------------------------------
                                                        Estimated                      Estimated
                                         Carrying         Fair          Carrying         Fair
                                          Amount          Value          Amount          Value
----------------------------------------------------- -------------- --------------- --------------
Assets:
<S>                                          <C>            <C>             <C>           <C>
  Cash and temporary cash investments        $18            $18             $1.0          $1.0
Liabilities:
  Short-term borrowings                     55.2           55.2             31.1          31.1
  Long-term debt                           285.0          321.1           293.5          328.3
----------------------------------------------------- -------------- --------------- --------------
</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. The carrying values reflect the fair
        values of derivatives designated as hedges under SFAS 133 criteria
        (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.




<PAGE>



          In January 2003 the Company filed a summary of its hedging program for
natural gas purchases with the NCUC for informational purposes. The primary goal
of the program is to reduce price volatility to firm customers. In an October
2003 order, the NCUC declared the program was reasonable. Transaction fees and
any gains or losses are recorded in deferred accounts for subsequent rate
consideration. As of December 31, 2003 the Company had deferred net costs of
approximately $2.2 million.

         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 fair value of interest rate swaps is recorded within other
deferred debits on the balance sheet. The resulting credits serve to reflect the
hedged long-term debt at its fair value. Periodic receipts or payments related
to the interest rate swaps are credited or charged to interest expense as
incurred.
..

         At December 31, 2003 the estimated fair value of the Company's swaps
totaled $1.9 million related to combined notional amounts of $33.1 million.

8. COMMITMENTS AND CONTINGENCIES

         A.  Environmental

         The Company is responsible for environmental cleanup at five sites in
North Carolina on which manufactured gas plant (MGP) residuals are present or
suspected. 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. The Company has recorded
a liability and associated regulatory asset of approximately $7.0 million, which
reflects its estimated remaining liability at December 31, 2003. Amounts
incurred and deferred to date that are not currently being recovered through gas
rates are approximately $2.2 million. Management believes that all MGP cleanup
costs will be recoverable through gas rates.

B.      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.

         C.    Purchase Commitments

         As of December 31, 2003 purchase commitments under forward contracts
for natural gas purchases are $266 million and $108 million for 2004 and 2005,
respectively.

         In addition, included in purchase commitments are customary purchase
orders under which the Company has the option to utilize certain vendors without
the obligation to do so. The Company may terminate such commitments without
penalty.


<PAGE>

<TABLE>
<CAPTION>

9. SEGMENT OF BUSINESS INFORMATION

         Gas Distribution is the Company's sole reportable segment, and
operating income is used to measure profitability. The Company did not have
deferred tax assets prior to 2002, and did not have intersegment revenue for any
period reported.

Disclosure of Reportable Segments (Millions of dollars)

--------------------------------------- -------------------- -------------- --------------------- ---------------
                                                Gas               All           Adjustments/       Consolidated
                 2003                      Distribution          Other          Eliminations          Total
--------------------------------------- -------------------- -------------- --------------------- ---------------

<S>                                              <C>                                                   <C>
External Revenue                                 $509               -                  -               $509
Depreciation & Amortization                        34               -                  -                  34
Operating Income                                   63             n/a                  -                  63
Interest Expense                                   21               -                  -                  21
Segment Assets                                 1,067              $28               $57               1,152
Expenditures for Assets                            48                -                 -                  48
Deferred Tax Assets                                  3               -                 -                    3
--------------------------------------- -------------------- -------------- --------------------- ---------------

--------------------------------------- -------------------- -------------- --------------------- ---------------
                                                Gas               All           Adjustments/       Consolidated
                 2002                      Distribution          Other          Eliminations          Total
--------------------------------------- -------------------- -------------- --------------------- ---------------

External Revenue                                $356                 -                -                $356
Depreciation & Amortization                        35                -                -                   35
Operating Income                                   54               n/a               -                   54
Interest Expense                                   21                -                -                   21
Segment Assets                                 1,010              $28                     $55         1,093
Expenditures for Assets                            48                -                -                   48
Deferred Tax Assets                                 3                -                -                    3
--------------------------------------- -------------------- -------------- --------------------- ---------------

--------------------------------------- -------------------- -------------- --------------------- ---------------
                                                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                                 1,187              $29                $5
                                                                                                  1,221
Expenditures for Assets                            75                -                -
                                                                                                  75
--------------------------------------- -------------------- -------------- --------------------- ---------------

10. QUARTERLY FINANCIAL DATA (UNAUDITED)

             Millions of dollars
---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------
                                                             First       Second      Third       Fourth
2003                                                        Quarter     Quarter     Quarter     Quarter      Annual
---------------------------------------------------------- ----------- ----------- ----------- ----------- -----------

Total operating revenues                                      $203        $82         $59         $165        $509
Operating income (loss)                                          42           -         (8)          29          63
Net income (loss)                                                24         (2)         (7)          16          31

             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                        (230)          -           -             -       (230)
Net income (loss)                                             (209)         (2)         (6)          10        (207)

</TABLE>

<PAGE>















                  PART II, ITEM 9 AND 9A, PART III AND PART IV


                                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


ITEM 9A.  CONTROLS AND PROCEDURES

SCANA:

             As of December 31, 2003, an evaluation was performed under the
supervision and with the participation of SCANA'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, SCANA's
management, including the CEO and CFO, concluded that SCANA's disclosure
controls and procedures were effective as of December 31, 2003. There has been
no change in SCANA's internal controls over financial reporting during the
quarter ended December 31, 2003 that has materially affected or is reasonably
likely to materially affect SCANA's internal control over financial reporting.

SCE&G:

             As of December 31, 2003, 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, 2003. There has been no change in SCE&G's internal
controls over financial reporting during the quarter ended December 31, 2003
that has materially affected or is reasonably likely to materially affect the
Company's internal control over financial reporting.

PSNC Energy:

             As of December 31, 2003, 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, 2003. There
has been no change in PSNC Energy's internal controls over financial reporting
during the quarter ended December 31, 2003 that has materially affected or is
reasonably likely to materially affect the Company's internal control over
financial reporting.


                                    PART III

 ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

SCANA: A list of SCANA's executive officers is in Part I of this annual report
at page 24. 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 2004 annual meeting of shareholders which will be filed with
the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange
Act of 1934 within 120 days after the end of SCANA's fiscal year.

CODE OF ETHICS

SCANA has adopted a code of ethics that applies to its principal executive
officer, principal financial officer and principal accounting officer or
controller. SCANA has posted the text of the code on its Internet website at
www.scana.com.



<PAGE>
<TABLE>
<CAPTION>



SCE&G:                                                                            DIRECTORS

       The directors listed below were elected May 1, 2003 (except as otherwise
indicated) to hold office until the next annual meeting of SCE&G's shareholders
to be held on April 29, 2004.

    Name and Year First
      Became Director         Age      Principal Occupation; Directorships

<S>                             <C>
       Bill L. Amick            60     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; PSNC Energy;
Blue Cross and Blue Shield of South Carolina.

      James A. Bennett          43     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.


                                       From December 1998 to February 2000,
                                         Senior Vice President and Director of
                                         Professional Banking, First Citizens
                                         Bank.

                                       Director, SCANA Corporation; PSNC Energy.

  William B. Bookhart, Jr.      62     For more than five years, a partner in Bookhart Farms, Elloree, SC (general farming).
           (1979)
                                       Director, SCANA Corporation; PSNC Energy.

    William C. Burkhardt        66     Since October 2003, Chief Executive Officer of Capital Bank, Raleigh, NC.
           (2000)

                                       From 1980 until May 2000 retirement,
                                       President and Chief Executive Officer of
                                       Austin Quality Foods, Inc., Cary, NC
                                       (production and distribution of baked
                                       snacks).

                                       Director, SCANA Corporation; PSNC Energy; Capital Bank Corp. and Belmont Plaza II, a Kansas
                                       City, KS Investment Fund.

     Elaine T. Freeman          68     For more than five years, Executive Director of ETV Endowment of South Carolina, Inc.
           (1992)                         (non-profit organization), Spartanburg, SC.

                                       Director, SCANA Corporation; PSNC Energy;
                                          National Bank of South Carolina (a
                                          member bank of Synovus Financial
                                          Corporation).




<PAGE>



     Name and Year First
       Became Director          Age    Principal Occupation; Directorships

      D.    Maybank Hagood 42 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; PSNC Energy.

        W. Hayne Hipp           64     For more than five years, Chairman and Chief Executive Officer of The Liberty
            (1983)                       Corporation, Greenville, SC (broadcasting holding company).

                                       Director, SCANA Corporation; PSNC Energy; The Liberty Corporation.

       Lynne M. Miller          52     For more than five years, Chief Executive Officer of Environmental Strategies Consulting
                                       LLC,
            (1997)                     formerly Environmental Strategies Corporation, Reston, VA (environmental consulting
                                       and engineering firm).

                                       Director, SCANA Corporation; PSNC Energy;
                                          Adams National Bank (a subsidiary of
                                          Abigail Adams National Bancorp, Inc.).

        Maceo K. Sloan          54     For more than five years, Chairman, President and Chief Executive Officer of Sloan Financial
            (1997)                        Group, Inc. (holding company) and Chairman, Chief Executive Officer and Chief
                                          Investment Officer of NCM Capital Management Group, Inc. (NCM) (investment
                                          management company), Durham, NC.

                                       Director, SCANA Corporation; PSNC Energy; M&F Bankcorp, Inc., a subsidiary of Mechanics
                                          and Farmers Bank; Trustee, Teachers Insurance Annuity Association - College Retirement
                                          Equity Fund (TIAA-CREF) Funds Boards.

       Harold C. Stowe* 57 For more than five years, President of Canal
            Holdings, LLC and its predecessor company, (1999) Conway, SC (forest
            products industry).

                                       Director, SCANA Corporation; PSNC Energy; New South Companies, Inc.; Ruddick
                                          Corporation.

     William B. Timmerman 57 For more than five years, Chairman of the Board,
            President and Chief Executive Officer, (1991) SCANA Corporation,
            Columbia, SC.

                                       Director, SCANA Corporation; PSNC Energy;
                                          ITC^DeltaCom; ITC Financial Services;
                                          The Liberty Corporation.

        G.  Smedes York 63 For more than five years, President and Treasurer of
            York Properties, Inc., Raleigh, NC. (2000) (full-service commercial
            and residential real estate company). Chairman of the Board of
                                         York Simpson Underwood (residential
                                         brokerage company) and McDonald-York,
                                         Inc. (general contractor).

                                       Director, SCANA Corporation; PSNC Energy.

</TABLE>

*Mr. Stowe is a member of the Audit Committee of SCE&G's board of directors and
has been determined by SCE&G's board of directors to be an audit committee
financial expert within the meaning of Item 401(h) of Regulation S-K. SCE&G's
board of directors has also determined that Mr. Stowe is independent, as that
term is used in Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.

<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             57     Chairman of the Board and Chief Executive Officer                         *-present

H. T. Arthur                58     Senior Vice President, General Counsel and Assistant Secretary            *-present

  S. D. Burch                47      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                 44     Senior Vice President-Nuclear Operations                                  2001-present
                                   Vice President-Nuclear Operations                                         2000-2001
                                   General Manager-Nuclear Plant Operations                                  *-2000

N. O. Lorick                53     President and Chief Operating Officer                                     2000-present
                                   Vice President - Fossil and Hydro Operations                              *-2000

K. B. Marsh                 48     Senior Vice President and Chief Financial Officer                         *-present
                                   Controller                                                                2000

*Indicates position held at least since March 1, 1999

</TABLE>

             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 2003 all Section 16(a) filing requirements
applicable to its officers, directors and greater than 10% beneficial owners
were complied with.

                                 CODE OF ETHICS

SCE&G has adopted a code of ethics that applies to its principal executive
officer, principal financial officer and principal accounting officer or
controller. SCE&G has posted the text of the code on its Internet website at
www.scana.com.


<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 2004 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>
W. B. Timmerman                      2003                    718,493           5,754               -    1,150,242        97,150
                                              858,219(5)
Chairman, President and Chief        2002       751,228      760,949         16,435        219,200        536,884        44,614
Executive Officer - SCANA            2001      660,238                       17,611        129,781                       60,884
                                                                -                                           -

N. O. Lorick                         2003      419,808       300,036           5,962              -       325,384        44,257
President and Chief Operating        2002      376,538       317,808         16,958        77,816         145,487           22,132
Officer - SCE&G                      2001       385,252                      18,701        36,711                        30,611
                                                            -                                               -

K. B. Marsh                          2003      419,808       300,036             928              -       325,384        44,257
Senior Vice President                2002      375,384       317,808         10,183        77,816         209,432        22,063
and Chief Financial Officer -        2001      334,234                       10,554        36,711                        29,097
                                                                -                                           -
SCANA

H. T. Arthur                         2003      360,950       180,675           5,106              -       169,634        33,603
Senior Vice President and            2002      297,115       191,340         15,830        42,992         146,345        17,367
General Counsel                      2001      270,963                       16,119        19,142                        23,487
                                                                -                                           -

S. A. Byrne                          2003      323,351       180,675               -              -       169,634        30,993
Senior Vice President-Nuclear        2002      285,385       191,339          9,000        42,992         146,345        16,663
Operations - SCE&G                   2001      244,232                        9,285        19,142                        22,064
                                                                -                                           -
------------------------------------ ------ --------------- ----------- ------------------------------ ------------ ---------------
</TABLE>

(1) Payments under the Annual Incentive Plan.
(2) For 2003, other annual compensation consists of life insurance premiums on
policies owned by named executive officers. (3) Payouts of performance share
awards under the Company's Long-Term Equity Compensation Plan. (4) All other
compensation for all named executive officers consists solely of Company
matching contributions to defined contribution plans.
(5) Reflects actual salary paid in 2003. Base salary of $870,900 became
effective on February 20, 2003.


<PAGE>


<TABLE>
<CAPTION>


Outstanding Options and Related Information


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

<S>                                                 <C>     <C>                           <C>       <C>
W. B. Timmerman                                     195,207/189,394                       1,391,752/1,277,650
N. O. Lorick                                         52,744/64,115                          361,391/432,351
K. B. Marsh                                          62,039/64,115                          442,722/432,351
H. T. Arthur                                         35,888/35,042                          260,188/236,280
S. A. Byrne                                          35,888/35,042                          260,188/236,280

(1)Based on the closing price of $34.25 per share on December 31, 2003, the last
trading day of the fiscal year.
</TABLE>

Long-Term Incentive Plans Awards

     The following table lists the performance share awards and the performance
unit awards made in 2003 (for potential payment in 2006) under the Long-Term
Equity Compensation Plan and estimated future payouts under that plan at
threshold, target and maximum levels for each of the executive officers included
in the Summary Compensation Table.
<TABLE>
<CAPTION>

                                              LONG-TERM INCENTIVE PLANS
                                             AWARDS IN LAST FISCAL YEAR

                           Number of        Performance                   Estimated Future Payouts Under
                            Shares,           or Other                     Non-Stock Price-Based Plans
                                                             ---------------------------------------------------------
                            Units or        Period Until
                             Other           Maturation          Threshold            Target             Maximum
Name                       Rights (#)        or Payout              (#)                (#)                 (#)
------------------------ --------------- ------------------- ------------------ ------------------- ------------------

<S>                           <C>            <C>  <C>             <C>                 <C>                 <C>
W. B. Timmerman               30,249         2003-2005            12,100              30,249              45,374
                              (1)
W. B. Timmerman               20,166         2003-2005            10,083              20,166              30,249
                              (2)
N. O. Lorick                  10,737         2003-2005              4,295              10,737             16,106
                              (1)
N. O. Lorick                   7,158         2003-2005              3,579               7,158             10,737
                              (2)
K. B. Marsh                  10,737 (1)      2003-2005              4,295             10,737              16,106
K. B. Marsh                    7,158         2003-2005              3,579               7,158            10,737
                              (2)
H. T. Arthur                   5,933         2003-2005              2,373               5,933             8,900
                              (1)
H. T. Arthur                  3,955 (2)      2003-2005              1,978               3,955             5,933
S. A. Byrne                    5,933         2003-2005              2,373               5,933             8,900
                              (1)
S. A. Byrne                   3,955 (2)      2003-2005              1,978               3,955             5,933

(1)  Performance Share Awards
(2)   Performance Unit Awards
</TABLE>

     Payouts on performance share awards occur when SCANA's total shareholder
return is in the top two-thirds of the Long-Term Equity Compensation Plan peer
group for that period, and will vary based on SCANA's ranking against that peer
group. Executives earn threshold payouts (40% of award) at the 33rd percentile
of three-year performance. Target payouts (100% of award) will be made at the
50th percentile of three-year performance. Maximum payouts (150% of award) will
be made when performance is at or above the 75th percentile of the peer group.
Payments will be made on a sliding scale for performance between threshold and
target and target and maximum. No payouts will be earned if performance is at
less than the 33rd percentile. Awards are designated as target shares of SCANA
common stock and may be paid in stock or cash or a combination of stock and
cash. Payouts on performance unit awards occur when SCANA's three-year average
growth in earnings per share from ongoing operations equals or exceeds 4%.
Executives earn threshold payments (50% of award) at 4% average growth, target
payments (100% of award) at 6% average growth and maximum payouts (150% of
award) at 8% average growth. No payouts will occur if average growth in earnings
per share from ongoing operations over the period is less than 4%. Awards are
designated as target units of SCANA common stock and may be paid in stock or
cash or a combination of stock and cash.

Defined Benefit Plans

     SCANA has a tax qualified defined benefit retirement plan. The plan has a
mandatory cash balance benefit formula (the "Cash Balance Formula") for
employees hired on or after January 1, 2000. Effective July 1, 2000, SCANA
employees hired prior to January 1, 2000 were given the choice of remaining
under the Retirement Plan's final average pay benefit formula or switching to
the cash balance benefit option. All the executive officers named in the Summary
Compensation Table elected to participate under the cash balance option of the
plan.

     The Cash Balance Formula benefit is expressed in the form of a hypothetical
account balance. 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 has
Supplemental Executive Retirement Plans ("SERPs") for certain eligible
employees, including officers. A SERP is an unfunded plan that provides for
benefit payments in addition to benefits payable under the qualified Retirement
Plan in order to replace benefits lost in the Retirement Plan because of
Internal Revenue Code maximum benefit limitations.

     The estimated annual retirement benefits payable as life annuities at age
65 under the plans, based on projected compensation (assuming increases of 4%
per year), to the executive officers named in the Summary Compensation Table are
as follows: Mr. Timmerman - $456,312; Mr. Lorick - $290,436; Mr. Marsh -
$349,416; Mr. Arthur - $114,180 and Mr. Byrne - $271,452.

Termination, Severance and Change in Control Arrangements

     SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust
is to help retain and attract quality leadership in key SCANA positions in the
current transitional environment of the utilities industry. The trust holds
SCANA contributions (if made) which may be used to pay the deferred 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 covered
        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 and performance unit
        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 2003, 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 Committee 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, 2003, compensation for
non-employee directors of SCANA and its subsidiaries has included the following:

o an annual retainer of $36,000 (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 day a
regular meeting of the Board is held; o $300 for participation in a telephone
conference meeting of 30 minutes or less, and $600 for participating in a longer
       conference;
o       $3,000 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 and 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 2003, the only
director participating in the Voluntary Deferral Plan was Mr. Bennett, whose
account was credited with interest of $2,366 for the year.

         Under the Director Compensation and Deferral 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 2003, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and
York and Ms. Miller 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 this Item is incorporated herein by
reference to the caption "Share Ownership of Directors, Nominees and Executive
Officers" and "Five Percent Ownership of SCANA Common Stock" and "Equity
Compensation Plan Information" within Item 2- approval of Amended Director
Compensation and Deferral Plan" in SCANA's definitive proxy statement for the
2004 annual meeting of shareholders.


<PAGE>




SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table lists shares of SCANA common stock beneficially owned on
February 23, 2004 by each director and each person named in the Summary
Compensation table in Item 11, Executive Compensation.
<TABLE>
<CAPTION>

          SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

                            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>                                                          <C>
B. L. Amick (6) (7)                      10,718               W. H. Hipp                              4,897
H. T. Arthur                             73,494               N. O. Lorick                         108,992
J. A. Bennett  (7)                         2,445              K. B. Marsh                          117,868
W. B. Bookhart, Jr. (6)                  23,515               L. M. Miller (7)                        3,542
(7)
W. C. Burkhardt (6) (7)                  12,142               M. K. Sloan (6) (7)                     4,498
S. A. Byrne                              63,572               H. C. Stowe (6) (7)                     4,377
E. T. Freeman (7)                        10,673               W. B. Timmerman                      368,659
D. M. Hagood (6) (7)                         850              G. S. York (7)                         12,219
</TABLE>

*Each of the above owns less than 1% of the shares outstanding.

All directors and executive officers as a group (17 persons) total 837,860
shares, including 625,832 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 Mr. Bookhart-6,601 shares owned by close relatives, the beneficial
ownership of which he disclaims. (2) Includes shares purchased through February
11, 2004, 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 23, 2004, each of the following directors had acquired under the
    plan, the number of hypothetical shares following
    his or her name:  Messrs. Amick-7,591, Bennett-7,060, Burkhardt-8,705,
    Hagood-2,755, Hipp-7,491, Sloan-7,815, Stowe-7,992,
    York-8,284 and  Ms. Miller-8,323.
(4) Includes shares subject to currently exercisable options and options that
    will become exercisable within 60 days in the following amounts: Messrs.
    Timmerman-311,535; Lorick-90,921; Marsh-100,215; Byrne-56,600;
    Arthur-56,600.
(5) Hypothetical shares acquired under the SCANA Executive Deferred Compensation
    Plan are not included in the above table. As of February 23, 2004, each of
    the following officers had acquired under the plan, the number of
    hypothetical shares following his or her name: Messrs. Timmerman-25,022;
    Lorick-4,703; Marsh-4,579; Byrne-2,711; Arthur-4,232.
(6) Human Resources Committee. (7) Long-Term Equity Compensation Plan Committee.


<PAGE>



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 caption "Related Party
Transactions" in SCANA's definitive proxy statement for the 2004 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 2004
annual meeting of shareholders shall not be incorporated by reference into any
such filings.

SCE&G: During 2003, SCANA incurred advertising expenses of $66,163 (including
the value of non-utility in-kind services provided by SCANA and its
subsidiaries) on account of advertising services provided by subsidiaries of The
Liberty Corporation. 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.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

SCANA: The information required by Item 14 is incorporated herein by reference
to Proposal 3 in SCANA's definitive proxy statement for the 2004 annual meeting
of shareholders.

SCE&G and PSNC Energy:

          SCANA's Audit Committee Charter requires the Audit Committee to
pre-approve all auditing services and permitted non-audit services (including
the fees and terms thereof) to be performed by the external auditors. Pursuant
to a policy adopted by the Audit committee, the Committee Chairman may
pre-approve the rendering of services on behalf of the Audit Committee.

Independent Auditors Fees

          The following table set forth the aggregate fees billed to SCE&G and
PSNC Energy for the fiscal years ended December 31, 2002 and 2003 by Deloitte &
Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective
affiliates.

                                   2003                         2002
                                   ----                         ----
                        SCE&G        PSNC Energy     SCE&G         PSNC Energy
                        -----        -----------     -----         -----------
Audit Fees (1)          $747,716       $143,661    $1,003,258       $232,068
Audit Related Fees (2)   348,301        72,200          53,418          5,440
Tax Fees (3)               32,053          2,813        36,998          2,960
All Other Fees (4)                                      78,958         40,000
                      ------------- --------------------------   ----  ------
                          -               -
Total Fees            $1,128,070       $218,674    $1,172,632       $280,468

(1) Fees for audit services billed in 2003 and 2002 consisted of audits of the
companies' annual financial statements, reviews of the companies quarterly
financial statements, comfort letters, statutory and regulatory audits, consents
and other services related to the Securities and Exchange Commission ("SEC"),
and accounting research.
(2) Includes Sarbanes-Oxley section 404 readiness assistance and employee
benefit plan audits for 2003, and employee benefit plan and subsidiary audits
for 2002. (3) Includes tax compliance and tax services.
(4) Includes depreciation studies in 2002.

          In 2003 and 2002 all of the Audit Related Fees, Tax Fees and All Other
Fees were approved by the Audit Committee.



<PAGE>



                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed or furnished as a part of 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 or furnished with this Annual
                    Report on Form 10-K are listed in the Exhibit Index
                    following the signature page. Certain of such exhibits which
                    have heretofore been filed with the Securities and Exchange
                    Commission and which are designated by reference to their
                    exhibit number in prior filings are incorporated herein by
                    reference and made a part hereof.

                    Pursuant to Rule 15d-21 promulgated under the Securities
                    Exchange Act of 1934, the annual report for SCANA's employee
                    stock purchase plan will be furnished under cover of Form
                    10-K/A to the Commission when the information becomes
                    available.

       As permitted under Item 601(b)(4)(iii)of Regulation S-K, instruments
defining the rights of holders of long-term debt of less than 10% of the total
consolidated assets of SCANA, for itself and its subsidiaries, of SCE&G, for
itself and its subsidiaries, and of PSNC Energy, for itself and its
subsidiaries, have been omitted and SCANA, SCE&G and PSNC Energy agree to
furnish a copy of such instruments to the Commission upon request.

(b) Reports on Form 8-K during the fourth quarter of 2003 for SCANA, SCE&G and
PSNC Energy:

       SCANA Corporation:
       Date of report:  October 27, 2003
       Items reported:  7 and 12

       South Carolina Electric & Gas Company:
       Date of report:   October 27, 2003
       Items reported:   7 and 12

       Date of report:   October 30, 2003
       Item reported:    5

       Date of report:   October 31, 2003
       Items reported:   5 and 7

       Public Service Company of North Carolina Incorporated:
       Date of report:   October 27, 2003
       Items reported:   7 and 12




<PAGE>
<TABLE>
<CAPTION>


SCANA:

Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2003, 2002 and 2001.

                                                                       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>
                  2003                       16,749,601       15,998,233            -           16,348,851       16,398,983
                  2002                       37,814,016       17,973,345            -           39,037,760       16,749,601
                  2001                       31,235,446       11,206,098            -             4,627,528      37,814,016

Reserve for investment impairment
                  2003                         4,477,050          125,000           -            4,477,050           125,000
                  2002                         4,928,768                            -               451,718        4,477,050
                                                                   -
                  2001                         4,928,768                            -                              4,928,768
                                                                   -                                 -

Reserves other than those deducted from assets on the balance sheet:

Reserve for injuries and damages
                  2003                         7,067,466       6,368,705            -            4,455,676        8,980,495
                  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

</TABLE>











<PAGE>



<TABLE>
<CAPTION>

SCE&G:

Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2003, 2002 and 2001.

                                                                    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>
                 2003                       694,000         4,666,778            -            4,409,602         951,176
                 2002                       820,000         3,119,886            -            3,245,886         694,000
                 2001                       577,000         3,273,754            -            3,030,754         820,000

Reserves other than those deducted from assets on the balance sheet:

Reserve for injuries and damages
                 2003                      4,366,819       10,449,561            -            8,761,210        6,055,170
                 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



</TABLE>















<PAGE>



<TABLE>
<CAPTION>


PSNC Energy:
Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31,
2003, 2002 and 2001.

                                                                    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:

<S>     <C>    <C>    <C>    <C>    <C>    <C>
Uncollectible accounts
                             2003       1,512,238           3,828,398            -            3,110,213         2,230,423
                             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

Reserves other than those deducted from assets on the balance sheet:

Reserve for injuries and damages
                             2003       1,239,698             810,000            -                645,541      1,404,157
                             2002       1,201,125             923,010            -                884,437      1,239,698
                             2001       1,626,258             723,628            -              1,148,761      1,201,125


</TABLE>





(a)Includes $309,645 uncollectible reserve balance for SCANA Public Service
Company LLC which was sold to SCANA Energy Marketing effective January 1, 2001.



<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:                                      February 27, 2004


       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated. The signatures of
the undersigned shall be deemed to relate only to matters having reference to
the registrant and any subsidiaries thereof.




                                           s/W. B. Timmerman
                                           W. B. Timmerman, Chairman of the
                                           Board, President, Chief Executive
                                           Officer and Director (Principal
                                           Executive Officer)



                                           s/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:  February 27, 2004


<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:                          February 27, 2004



       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated. The signatures of
the undersigned shall be deemed to relate only to matters having reference to
the registrant and any subsidiaries thereof.





                                       s/W. B. Timmerman
                                       W. B. Timmerman, Chairman of the Board,
                                       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:                                                    February 27, 2004



<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:                          February 27, 2004


       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated. The signatures of
the undersigned shall be deemed to relate only to matters having reference to
the registrant and any subsidiaries thereof.





                                       s/W.     B. Timmerman
                                       W.       B. Timmerman, Chairman of the
                                                Board, 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:                                                 February 27, 2004



<PAGE>
<TABLE>
<CAPTION>



                                  EXHIBIT INDEX

               Applicable to Form 10-K of
Exhibit                              PSNC
No. SCANA SCE&G Energy Description
<S>                                         <C>
3.01             X                          Restated Articles of Incorporation of SCANA Corporation as adopted on April
                                            26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and
                                            incorporated by reference herein)
3.02             X                          Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to
                                            Registration Statement No. 33-62421 and incorporated by reference herein)

3.03                        X               Restated Articles of Incorporation of South Carolina Electric & Gas
                                            Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to Registration
                                            Statement No. 333-65460 and incorporated by reference herein)

   .04                      X               Articles of Amendment effective as of the dates indicated below and filed
                                            as exhibits to the Registration Statements set forth below and are
  3                                         incorporated by reference herein
                                            1.
                                            May 22, 2001       Exhibit 3.02      to Registration No. 333-65460
                                            June 14, 2001      Exhibit 3.04      to Registration No. 333-65460
                                            August 30, 2001    Exhibit 3.05      to Registration No. 333-101449
                                            March 13, 2002     Exhibit 3.06      to Registration No. 333-101449
                                            May 9, 2002        Exhibit 3.07      to Registration No. 333-101449
                                            June 4, 2002       Exhibit 3.08      to Registration No. 333-101449
                                            August 12, 2002    Exhibit 3.09      to Registration No. 333-101449
                                            March 13, 2003     Exhibit 3.05      to Registration No. 333-108760
                                            May 22, 2003       Exhibit 3.05      to Registration No. 333-108760
                                            June 18, 2003      Exhibit 3.06      to Registration No. 333-108760
                                            August 7, 2003     Exhibit 3.06      to Registration No. 333-108760

3.05                        X               Articles of Correction filed on June 1, 2001 correcting May 22, 2001
                                            Articles of Amendment (Filed as Exhibit 3.03 to Registration Statement No.
                                            333-65460 and incorporated by reference herein)

3.06                        X               Articles of Correction filed on February 17, 2004 correcting May 3, 2001
                                            Restated Articles of Incorporation (Filed herewith)

3.07                        X               Articles of Correction filed on February 17, 2004 correcting May 22, 2001
                                            Articles of Amendment (Filed herewith)

3.08                        X               Articles of Correction filed on February 17, 2004 correcting June 14, 2001
                                            Articles of Amendment (Filed herewith)

3.09                        X               Articles of Correction filed on February 17, 2004 correcting August 30,
                   2001 Articles of Amendment (Filed herewith)

3.10                        X               Articles of Correction filed on February 17, 2004 correcting March 13, 2002
                                            Articles of Amendment (Filed herewith)

3.11                        X               Articles of Correction filed on February 17, 2004 correcting May 9, 2002
                                            Articles of Amendment (Filed herewith)

3.12                        X               Articles of Correction filed on February 17, 2004 correcting June 4, 2002
                                            Articles of Amendment (Filed herewith)


                                  EXHIBIT INDEX

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

3.13                        X               Articles of Correction filed on February 17, 2004 correcting August 12, 2002
                                            Articles of Amendment (Filed herewith)

3.14                        X               Articles of Correction filed on February 17, 2004 correcting March 13, 2003
                                            Articles of Amendment (Filed herewith)

3.15                        X               Articles of Correction filed on February 17, 2004 correcting May 22, 2003 Articles
                                            of Amendment (Filed herewith)

3.16                        X               Articles of Correction filed on February 17, 2004 correcting June 18, 2003
                                            Articles of Amendment (Filed herewith)

3.17                        X               Articles of Correction filed on February 17, 2004 correcting August 7, 2003
                                            Articles of Amendment (Filed herewith)

3.18             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)

3.19                        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)

3.20                                   X      By-Laws of PSNC Energy 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)




<PAGE>


                                  EXHIBIT INDEX

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

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  set forth below and are incorporated by reference herein

                                              December 1, 1950               Exhibit 2-D         to Registration No. 2-26459
                                              July 1, 1951                   Exhibit 2-E         to Registration No. 2-26459
                                              June 1, 1953                   Exhibit 2-F         to Registration No. 2-26459
                                              June 1, 1955                   Exhibit 2-G         to Registration No. 2-26459
                                              November 1, 1957               Exhibit 2-H         to Registration No. 2-26459
                                              September 1, 1958              Exhibit 2-I         to Registration No. 2-26459
                                              September 1, 1960              Exhibit 2-J         to Registration No. 2-26459
                                              June 1, 1961                   Exhibit 2-K         to Registration No. 2-26459
                                              December 1, 1965               Exhibit 2-L         to Registration No. 2-26459
                                              June 1, 1966                   Exhibit 2-M         to Registration No. 2-26459
                                              June 1, 1967                   Exhibit 2-N         to Registration No. 2-29693
                                              September 1, 1968              Exhibit 4-O         to Registration No. 2-31569
                                              June 1, 1969                   Exhibit 4-C         to Registration No. 33-38580
                                              December 1, 1969               Exhibit 4-O         to Registration No. 2-35388
                                              June 1, 1970                   Exhibit 4-R         to Registration No. 2-37363
                                              March 1, 1971                  Exhibit 2-B-17      to Registration No. 2-40324
                                              January 1, 1972                Exhibit 2-B         to Registration No. 33-38580
                                              July 1, 1974                   Exhibit 2-A-19      to Registration No. 2-51291
                                              May 1, 1975                    Exhibit 4-C         to Registration No. 33-38580
                                              July 1, 1975                   Exhibit 2-B-21      to Registration No. 2-53908
                                              February 1, 1976               Exhibit 2-B-22      to Registration No. 2-55304
                                              December 1, 1976               Exhibit 2-B-23      to Registration No. 2-57936
                                              March 1, 1977                  Exhibit 2-B-24      to Registration No. 2-58662
                                              May 1, 1977                    Exhibit 4-C         to Registration No. 33-38580
                                              February 1, 1978               Exhibit 4-C         to Registration No. 33-38580
                                              June 1, 1978                   Exhibit 2-A-3       to Registration No. 2-61653
                                              April 1, 1979                  Exhibit 4-C         to Registration No. 33-38580
                                              June 1, 1979                   Exhibit 2-A-3       to Registration No. 33-38580
                                              April 1, 1980                  Exhibit 4-C         to Registration No. 33-38580
                                              June 1, 1980                   Exhibit 4-C         to Registration No. 33-38580
                                              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


                                  EXHIBIT INDEX

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

                                              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     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)

4.10               X                    X     First through Fourth Supplemental Indenture referred to Exhibit 4.09 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

4.11               X                    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          X         X     SCANA Executive Deferred Compensation Plan as amended February 20, 2003 (Filed
                                              as Exhibit 10.01 to Form 10-Q for the quarter ended June 30, 2003 and
                                              incorporated by reference herein)

*10.02             X          X         X     SCANA Director Compensation and Deferral Plan as amended January 1, 2001 (Filed
                                              as Exhibit 4.03 to Registration Statement No. 333-18973 and incorporated by
                                              reference herein)

*10.03             X          X         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)




<PAGE>



                                  EXHIBIT INDEX

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

*10.04          X          X          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)

*10.05          X          X          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)

*10.06          X          X          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)

*10.07          X          X          X       Request for Action by the SCANA Long-Term Equity Compensation Plan Committee of the
                                              Board dated August 1, 2002 (Filed as Exhibit 10.06 to Form 10-Q for the quarter ended
                                              June 30, 2003 and incorporated by reference herein)

*10.08          X          X          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)

*10.09          X          X          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)

10.10                                 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       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)

10.15                      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                             Statement Re Computation of Ratios

12.02                      X                  Statement Re Computation of Ratios




<PAGE>


                                  EXHIBIT INDEX

               Applicable to Form 10-K of
Exhibit                              PSNC
No.           SCANA      SCE&G      Energy    Description
12.03                                 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)

31.01           X                             Certification of Principal Executive Officer Required  by Rule 13a-14 (Filed herewith)

31.02           X                             Certification of Principal Financial Officer Required  by Rule 13a-14 (Filed herewith)

31.03                      X                  Certification of Principal Executive Officer Required  by Rule 13a-14 (Filed herewith)

31.04                      X                  Certification of Principal Financial Officer Required  by Rule 13a-14 (Filed herewith)

31.05                                 X       Certification of Principal Executive Officer Required  by Rule 13a-14 (Filed herewith)

31.06                                 X       Certification of Principal Financial Officer Required  by Rule 13a-14 (Filed herewith)

32.01           X                             Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)

32.02           X                             Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)

32.03                      X                  Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)

32.04                      X                  Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)

32.05                                 X       Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)

32.06                                 X       Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350
                                              (Furnished herewith)



* Management Contract or Compensatory Plan or Arrangement

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