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, 2000

                                       OR

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

                        For the Transition Period from to

Commission   Registrant, State of Incorporation,               I.R.S. Employer
File Number   Address and Telephone Number                    Identification No.

1-8809       SCANA Corporation                                        57-0784499
             (a South Carolina Corporation)
             1426 Main Street, Columbia, South Carolina  29201
             (803)  217-9000

1-3375       South Carolina Electric & Gas Company                    57-0248695
             (a South Carolina Corporation)
             1426 Main Street, Columbia, South Carolina  29201
             (803)  217-9000

1-11429      Public Service Company of North Carolina, Incorporated   56-2128483
             (a South Carolina Corporation)
             1426 Main Street, Columbia, South Carolina   29201
             (803)  217-9000

Securities registered pursuant to Section 12(b) of the Act:

Each of the  following  classes or series of securities is registered on the New
York Stock Exchange.

Title of each class                       Registrant

Common Stock, without par value           SCANA Corporation


5% Cumulative Preferred Stock             South Carolina Electric & Gas Company
par value $50 per share

7.55% Trust Preferred Securities,
Series A liquidation value $25            South Carolina Electric & Gas Company
per Trust Preferred Security






<PAGE>




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

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

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

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

         The aggregate  market value of voting stock held by  non-affiliates  of
SCANA  Corporation  was $2.8 billion at February  28, 2001,  based on a price of
$27.21.  Each of the other  registrants  is a  wholly-owned  subsidiary of SCANA
Corporation  and has no voting stock other than its common stock.  A description
of registrants' common stock follows:

                               Shares Outstanding
 Registrant               Description of Common Stock      at February 28, 2001
 ----------               ---------------------------      --------------------

SCANA Corporation              Without Par Value                104,729,131

South Carolina Electric
and Gas Company                 $4.50 Par Value                  40,296,147

Public Service Company of
North Carolina,Incorporated     Without Par Value                     1,000

         Documents  incorporated  by  reference:  Specified  sections  of  SCANA
Corporation's 2001 Proxy Statement, dated March 19, 2001, in connection with its
2001 Annual Meeting of  Stockholders,  are incorporated by reference in Part III
hereof.

This combined Form 10-K is separately filed by SCANA Corporation, South Carolina
Electric  &  Gas  Company  and  Public  Service   Company  of  North   Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.

Public Service Company of North Carolina,  Incorporated meets the conditions set
forth in General  Instruction  I (1) (a) and (b) of Form 10-K and  therefore  is
filing  this form with the  reduced  disclosure  format  allowed  under  General
Instruction I (2).








<PAGE>




                                                     TABLE OF CONTENTS

                                                                           Page

DEFINITIONS..............................................................     4

PART I

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

     Item 2.  Properties ................................................    18

     Item 3.  Legal Proceedings..........................................    20

     Item 4.  Submission of Matters to a Vote of Security Holders .......    20

     Corporate Structure ................................................    21

     Executive Officers of SCANA Corporation ............................    22

PART II

     Item 5.  Market for Registrant's Common Equity and
               Related Stockholder Matters...............................    23

     Item 6.  Selected Financial Data....................................    24

     Item 7.    Management's Discussion and Analysis of Financial Condition
                 and Results of Operations
     Item 7A.   Quantitative Disclosures About Market Risk
     Item 8.    Financial Statements and Supplementary Data

              SCANA Corporation..........................................    25

              South Carolina Electric & Gas Company......................    75

     Item 7.      Management's Narrative Analysis of Results of Operations
     Item 7A.   Quantitative Disclosures About Market Risk
     Item 8.      Financial Statements and Supplementary Data

              Public Service Company of North Carolina, Incorporated.....   109

     Item 9.  Changes in and Disagreements with Accountants on Accounting
               and Financial Disclosure..................................   138

PART III

     Item 10. Directors and Executive Officers of the Registrants........   138

     Item 11. Executive Compensation ....................................   142

     Item 12. Security Ownership of Certain Beneficial Owners
               and Management ...........................................   148

     Item 13. Certain Relationships and Related Transactions ............   149

PART IV

     Item 14. Exhibits, Financial Statement Schedules, and Reports
                on Form 8-K .............................................   150

SIGNATURES...............................................................   154


<PAGE>



                                   DEFINITIONS

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

TERM                      MEANING
AFC...................... Allowance for Funds Used During Construction
BTU...................... British Thermal Unit
CAA...................... Clean Air Act Amendments of 1990
Circuit Court............ South Carolina Circuit Court
Consumer Advocate........ Consumer Advocate of South Carolina
Dekatherm................ One Million BTUs
DHEC..................... South Carolina Department of Health and Environmental
                           Control
DOE...................... United States Department of Energy
DT....................... Dekatherm
Energy Marketing......... SCANA Energy Marketing, Inc.
EPA...................... United States Environmental Protection Agency
FERC..................... United States Federal Energy Regulatory Commission
Fuel Company............. South Carolina Fuel Company, Inc.
GENCO.................... South Carolina Generating Company, Inc.
Investor Plus Plan....... SCANA Corporation Investor Plus Plan
KVA...................... Kilovolt-ampere
KW....................... Kilowatt
KWH...................... Kilowatt-hour
LLC...................... Limited Liability Company
LNG...................... Liquefied Natural Gas
MCF...................... Thousand Cubic Feet
MGP...................... Manufactured Gas Plant
Mhz...................... Megahertz
MMBTU.................... Million British Thermal Unit
MMCF..................... Million Cubic Feet
MW....................... Megawatt
NEPA..................... National Energy Policy Act of 1992
NCUC..................... North Carolina Utilities Commission
NRC...................... United States Nuclear Regulatory Commission
PCS...................... Personal Communications Service
Pipeline Corporation..... South Carolina Pipeline Corporation
PRP...................... Potentially Responsible Party
PSC...................... The Public Service Commission of South Carolina
PSNC..................... Public Service Company of North Carolina, Incorporated
PUHCA.................... Public Utility Holding Company Act of 1935, as amended
RTO...................... Regional Transmission Organization
SCI...................... SCANA Communications, Inc.
SCANA.................... SCANA Corporation, the parent company
SCE&G.................... South Carolina Electric & Gas Company
SEC...................... United States Securities and Exchange Commission
Southern Natural......... Southern Natural Gas Company
SPSP..................... SCANA Corporation Stock Purchase-Savings Plan
Summer Station........... V. C. Summer Nuclear Station
Supreme Court............ South Carolina Supreme Court
Transco.................. Transcontinental Gas Pipeline Corporation
Williams Station......... A. M. Williams Coal-Fired, Electric Generating Station
                           Owned by GENCO
WNA       Weather Normalization Adjustment


<PAGE>



                                     PART I

ITEM 1.  BUSINESS


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,  concurrent with the completion of its
acquisition of PSNC.  SCANA holds,  directly or  indirectly,  all of the capital
stock of each of its  subsidiaries  except for the preferred stock of SCE&G, the
preferred  securities of SCE&G Trust I and 30 percent of an indirect subsidiary.
SCANA  and  its  subsidiaries  (the  Company)  had  5,426  full-time,  permanent
employees  as of February  28, 2001 as  compared to 5,488  full-time,  permanent
employees  as of February  29, 2000.  SCE&G was  incorporated  under the laws of
South  Carolina in 1924,  and is an operating  public  utility.  SCE&G had 2,412
full-time,  permanent  employees  as of  February  28, 2001 as compared to 3,771
full-time,  permanent employees as of February 29, 2000. Prior to being acquired
by  SCANA,  PSNC was  incorporated  under  the laws of North  Carolina  in 1938.
Subsequent  to its  acquisition,  PSNC is  incorporated  under the laws of South
Carolina.  PSNC is an  operating  public  utility  in  North  Carolina  with 653
full-time,  permanent  employees  as of  February  28,  2001 as  compared to 879
full-time, permanent employees as of February 29, 2000.

SEGMENTS OF BUSINESS

       SCANA  neither  owns nor  operates  any  physical  properties.  It has 11
direct,  wholly owned subsidiaries that are engaged in the functionally distinct
operations  described  below. It also has investments in two LLCs: one has built
and operates a cogeneration facility in Charleston, South Carolina and the other
has  constructed and operates a lime  production  facility in Charleston,  South
Carolina.  SCANA also has four other direct,  wholly owned subsidiaries that are
in liquidation.

       Information  with  respect to major  segments of  business  for the years
ended December 31, 2000, 1999 and 1998 is contained in  Management's  Discussion
and  Analysis of Financial  Condition  and Results of  Operations  for SCANA and
SCE&G and the Notes to Consolidated  Financial  Statements  appearing in Item 8,
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 14), SCE&G (Note 13)
and PSNC (Note 14). All such information is incorporated herein by reference.

Regulated Utilities

       SCE&G  is  a  regulated   public  utility   engaged  in  the  generation,
transmission, distribution and sale of electricity and in the purchase and sale,
primarily at retail, of natural gas in South Carolina.  SCE&G also renders urban
bus  service in the  metropolitan  area of  Columbia,  South  Carolina.  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 31 of the
46 counties in South  Carolina  and covers more than 21,000  square  miles.  The
total  population  of the counties  representing  the  combined  service area is
approximately 2.5 million.

       Predominant  industries in the areas served by SCE&G  include:  synthetic
fibers; chemicals;  fiberglass;  paper and wood; metal fabrication;  stone, clay
and sand mining and processing; and textile.

       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.


<PAGE>




       Pipeline Corporation is engaged in the purchase, transmission and sale of
natural gas on a  wholesale  basis to  distribution  companies  and  directly to
industrial  customers  in  41  counties  throughout  South  Carolina.   Pipeline
Corporation 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 Pipeline  Corporation are primarily engaged in the manufacturing or
processing of ceramics,  paper, metal, food and textiles.  Pipeline  Corporation
also  operates a 62-mile  six-inch  propane  pipeline  that is owned by Suburban
Propane, L.P. of Whippany, New Jersey.

       On February 10, 2000 SCANA  completed its  acquisition of PSNC. PSNC is a
public  utility  engaged  primarily in  transporting,  distributing  and selling
natural gas to  approximately  370,000  residential,  commercial  and industrial
customers.  PSNC provides service to 25 of its 28 franchised  counties  covering
approximately 11,500 square miles in North Carolina. The industrial customers of
PSNC include  manufacturers or processors of textiles,  chemicals,  ceramics and
clay products, glass, automotive products, minerals, pharmaceuticals,  plastics,
metals,  electronic  equipment,  furniture  and a  variety  of food and  tobacco
products.  PSNC,  through  wholly  owned,  non-regulated  subsidiaries,  refuels
natural gas  vehicles  and  converts  gasoline-fueled  vehicles to natural  gas.
Effective January 1, 2001,  PSNC's gas brokering  activities were transferred to
Energy Marketing.

Nonregulated Businesses

       Energy  Marketing  markets  electricity,  natural  gas  and  other  light
hydrocarbons  primarily  in  the  southeast.  Energy  Marketing,  also  provides
energy-related risk management services to producers and customers. In addition,
SCANA  Energy,  a  division  of  Energy   Marketing,   markets  natural  gas  to
approximately 432,000 customers in Georgia's deregulated natural gas market.

       SCI owns and operates a 500-mile fiber optics telecommunications  network
in South Carolina. In addition, SCI provides tower site construction, management
and rental  services in South  Carolina  and  Georgia.  SCI also owns an 800 Mhz
radio service network within the state, and in January 2001,  signed a letter of
intent  to sell  the  network.  The  sale  is  expected  in  April  2001.  SCANA
Communications  Holdings,  Inc. (SCH), a Delaware corporation and a wholly owned
subsidiary of SCI, has investments in Powertel, Inc., ITC Holding Company, Inc.,
ITC^DeltaCom,  Inc., and Knology,  Inc., which are  telecommunications  services
companies in the  southeastern  United States.  On August 28, 2000 SCH announced
that  Powertel  has  agreed to be  acquired  by either  Deutsche  Telekom  AG or
VoiceStream  Wireless  Corporation,  as further  discussion under "Other" in the
Liquidity and Capital Resources section of Management's  Discussion and Analysis
of Financial Condition and Results of Operations for SCANA.

       ServiceCare,  Inc. is engaged in  providing  energy-related  products and
services  beyond  the  energy  meter.  Its  primary   businesses  are  providing
homeowners  with service  contracts on their home  appliances  and home security
services.  ServiceCare  has  announced  the sale of its home  security  business
expected to be completed in March 2001.

       Primesouth, Inc. is engaged in power plant management and maintenance
services.

       SCANA Resources, Inc. conducts energy-related businesses and provides
energy-related services.

Service Company

         SCANA Services, Inc. provides administrative, management and other
services to the subsidiaries and business units within the Company.

COMPETITION

       For a  discussion  of the  impact  of  competition,  see the  Competition
section of  Management's  Discussion  and  Analysis of Financial  Condition  and
Results of Operations for SCANA and SCE&G.


<PAGE>




CAPITAL REQUIREMENTS AND FINANCING PROGRAM

Capital Requirements

       The Company's cash  requirements  arise primarily from SCE&G's and PSNC's
operational  needs,  the Company's  construction  program,  the need to fund the
activities or investments of SCANA's  nonregulated  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.  Depending on customer growth
and  inflation,  and  as  the  regulated  subsidiaries  continue  their  ongoing
construction  programs,  it may be  necessary 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  Regulatory  Matters in the  Liquidity  and  Capital
Resources section of Management's Discussion and Analysis of Financial Condition
and  Results  of  Operations  for SCANA and SCE&G and the Notes to  Consolidated
Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA for SCANA (Note 4), SCE&G (Note 3) and PSNC (Note 5).

       During 2001 the  Company is  expected  to meet its  capital  requirements
principally through internally generated funds (approximately 61 percent,  after
payment of dividends) and the incurrence of additional  short-term and long-term
indebtedness.  Sales of additional equity securities may also occur. The Company
expects  that it has or can obtain  adequate  sources of  financing  to meet its
projected  cash  requirements  for the next 12  months  and for the  foreseeable
future.

       The Company's current estimates of its cash requirements for construction
and  nuclear  fuel  expenditures,  which are  subject to  continuing  review and
adjustment, for 2001 and the two-year period 2002-2003 are as follows:

-------------------------------------------------------------- -----------------
Type of Facilities                           2002-2003               2001
                                                 (Millions of Dollars)

South Carolina Electric & Gas Company:
 Electric Plant:
       Generation                                $329                $249
       Transmission                                43                  22
       Distribution                               178                  83
       Other                                       17                  15
   Nuclear Fuel                                    36                  26
   Gas                                             38                  20
   Common                                          17                   6
   Other                                            1                   1
-------------------------------------------------------------- -----------------
       Total SCE&G                                659                 422
PSNC Gas                                           91                  42
Other Companies Combined                          193                  63
-------------------------------------------------------------- -----------------
                Total                            $943                $527
-------------------------------------------------------------- -----------------

         During 2000 SCE&G and GENCO  expended  approximately  $23.2 million and
$0.5 million,  respectively,  as part of a program to extend the operating lives
of certain non-nuclear generating facilities. Additional improvements to be made
under the program  during 2001,  included in the table above,  are  estimated to
cost approximately $80.3 million for SCE&G.

       In addition to the capital  requirements  for 2001 described  above,  the
Company,  SCE&G and PSNC will require approximately $41.5 million, $28.2 million
and $4.3 million,  respectively, to refund and retire outstanding securities and
obligations  in 2001. For the years  2002-2005,  the Company has an aggregate of
$1,705.4  million of long-term  debt  maturing,  which  includes an aggregate of
$455.2 million for SCE&G,  $2.2 million of purchase or sinking fund requirements
for SCE&G's  preferred stock and $22.5 million for PSNC.  SCE&G's long-term debt
maturities  for the years  2002-2005  include  approximately  $94.0  million for
sinking fund  requirements,  of which $93.9  million may be satisfied by deposit
and  cancellation  of bonds issued upon the basis of property  additions or bond
retirement credits.

        SCANA and  Westvaco  each own a 50 percent  interest  in Cogen South LLC
(Cogen).  Cogen was  formed to build and  operate  a  cogeneration  facility  at
Westvaco's Kraft Division Paper Mill in North  Charleston,  South Carolina.  The
facility  began  operations in March 1999. On September 10, 1998, the contractor
in charge of construction filed suit in Circuit Court seeking  approximately $52
million  from  Cogen,  alleging  that it  incurred  construction  cost  overruns
relating  to the  facility  and  that the  construction  contract  provides  for
recovery of these costs.  In addition to Cogen,  Westvaco,  SCE&G and SCANA were
also named as defendants in the suit. SCANA and the other defendants believe the
suit is without merit and are mounting an appropriate  defense.  SCANA and SCE&G
do not believe that the resolution of this issue will have a material  impact on
their results of operations, cash flows or financial position.

        On October 15, 1999 FERC notified  SCE&G of its  agreement  with SCE&G's
plan to  reinforce  Lake Murray Dam in order to maintain  the lake in case of an
extreme earthquake.  SCE&G and FERC have been discussing possible  reinforcement
alternatives  for the dam over the past several years as part of SCE&G's ongoing
hydroelectric  operating license with FERC. Until discussions are concluded,  it
is not  possible to finalize the cost of the  project;  however,  it is possible
that the cost could range up to $250  million.  Although  any costs  incurred by
SCE&G are  expected to be  recoverable  through  electric  rates,  SCE&G also is
exploring  alternative  sources  of  funding.  The  project  is  expected  to be
completed in 2004.

        On  September  21,  1999 SCE&G  announced  a $256  million  gas  turbine
generator project in Aiken County, South Carolina.  Two combined-cycle  turbines
will burn natural gas to produce 300  megawatts of new electric  generation  and
use  exhaust  heat to replace  coal-fired  steam that  powers  two  existing  75
megawatt  turbines at the Urquhart  Generating  Station.  The turbine project is
scheduled to be completed by June 2002.

        On October 7, 2000 Summer Station was removed from service for a planned
maintenance and refueling outage  scheduled to last 38 1/2 days.  During initial
inspection  activities,  plant  personnel  discovered a small leak coming from a
hole in a weld in a primary  coolant  system  pipe.  SCE&G  performed  extensive
ultrasonic testing of similar welds in the cooling system,  which confirmed that
the problem was limited to this single  weld. A root cause  analysis  determined
that the cause of the crack was primary  water stress  corrosion  cracking.  The
repair involved cutting out a twelve-inch long spool of the pipe, which included
the entire weld, and  installing a new spool piece.  Repairs have been completed
and the integrity of the new welds have been verified through extensive testing.
The plant was  returned to service in March 2001.  The NRC was closely  involved
throughout  this process and approved  SCE&G's  actions to repair the crack,  as
well as the restart  schedule.  SCE&G will continue to monitor  primary  coolant
system  pipes  during  the next  outage,  scheduled  for  Spring of 2002.  SCE&G
recorded a pretax charge of  approximately  $6 million in the fourth  quarter of
2000 to expense repair costs to date.  Additional  costs that may be recorded in
the  first  quarter  of 2001  are  not  expected  to be  material.  The  cost of
replacement  power is expected to be recovered  through  SCE&G's  electric  fuel
adjustment clause.

        In January 2001 SCE&G's 385 megawatt  coal-fired Cope Generating Station
was taken out of service due to an electrical ground in the generator.  The unit
is expected to be returned to service in Spring  2001.  The cost of  replacement
power is expected to be recovered through SCE&G's fuel adjustment clause.

Financing Program

       SCANA and PSNC each have in effect a  medium-term  note  program  for the
issuance from time to time of unsecured medium-term debt securities. At December
31, 2000 SCANA had registered with the SEC and available for issuance $1 billion
under its program,  the proceeds of which may be used to refinance  indebtedness
incurred in connection with the acquisition of PSNC, to fund additional business
activities in nonutility subsidiaries,  to reduce short-term debt or for general
corporate purposes.

       SCE&G's First and Refunding Mortgage Bond Indenture,  dated April 1, 1945
(Old Mortgage), contains provisions prohibiting the issuance of additional bonds
thereunder  (Class A Bonds)  unless net  earnings  (as therein  defined)  for 12
consecutive  months out of the 18 months  prior to the month of issuance  are at
least  twice  the  annual  interest  requirements  on all  Class A  Bonds  to be
outstanding  (Bond Ratio).  For the year ended  December 31, 2000 the Bond Ratio
was 6.43. The Old Mortgage allows the issuance of additional Class A Bonds to an
additional  principal  amount  equal to (i) 70 percent of unfunded  net property
additions (which unfunded net property  additions totaled  approximately  $1,452
million  at  December  31,  2000),  (ii)  retirements  of  Class A Bonds  (which
retirement  credits totaled $68.4 million at December 31, 2000),  and (iii) cash
on deposit with the Trustee.

       SCE&G is 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 (of which $665 million were  available for such purpose at December 31,
2000).  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, 2000
the New Bond Ratio was 6.34.

       The following  additional  financing  transactions  have  occurred  since
January 1, 2000:

o    On February 8, 2000 the Company  issued $400  million of two-year  floating
     rate notes  maturing  February 8, 2002.  The interest  rate on the notes is
     reset  quarterly  based on  three-month  LIBOR  plus 50 basis  points.  The
     proceeds from these  privately  sold notes were used to consummate  SCANA's
     acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a
     three-year term under a credit  agreement with several banks.  The interest
     rate is reset  every  one,  two,  three or six months and is based on LIBOR
     plus 100 basis  points.  These funds also were used to  consummate  SCANA's
     acquisition of PSNC.

o    On June 14, 2000 SCE&G issued $150 million of First  Mortgage  Bonds having
     an annual  interest rate of 7.50 percent and maturing on June 15, 2005. The
     proceeds  from the sale of these  bonds  were used to pay the  maturity  of
     SCE&G's  $100 million  First  Mortgage  Bonds due June 15, 2000,  to reduce
     short-term debt and for general corporate purposes.

o    On July 13, 2000 SCANA issued $300  million  two-year  floating  rate notes
     maturing on July 15, 2002.  The interest rate is reset  quarterly  based on
     three-month LIBOR plus 65 basis points. Proceeds from the debt were used to
     repay  medium-term  notes totaling $170 million,  to reduce short-term debt
     and for general corporate purposes.

o    On January 24, 2001 SCANA issued $202 million two-year  floating rate notes
     maturing on January 24, 2003. The interest rate is reset quarterly based on
     three-month  LIBOR plus 110 basis points.  Proceeds from the debt were used
     to reduce short-term debt and for general corporate purposes.

o    On January 24, 2001 SCE&G issued $150 million First  Mortgage  Bonds having
     an annual  interest  rate of 6.70 percent and maturing on February 1, 2011.
     The  proceeds  from the sale of these bonds were used to reduce  short-term
     debt and for general corporate purposes.

o    On February 16, 2001 PSNC issued $150 million of  medium-term  notes having
     an annual interest rate of 6.625 percent and maturing on February 15, 2011.
     These funds were used to reduce  short-term debt and for general  corporate
     purposes.

        The  Company's  electric  and natural  gas  businesses  are  seasonal in
nature,  with the primary demand for electricity being experienced during summer
and winter and the  primary  demand for  natural  gas being  experienced  during
winter.  As a result of the significant  increase during the latter half of 2000
in the cost to the Company of natural  gas and the colder  than  normal  weather
experienced in December,  the Company experienced  significant  increases in its
working  capital  requirements,  contributing  to the need for the financings by
SCANA and PSNC in early 2001 described above.

       Without the consent of at least a majority of the total  voting  power of
SCE&G's   preferred  stock,   SCE&G  may  not  issue  or  assume  any  unsecured
indebtedness  if, after such issue or assumption,  the total principal amount of
all such  unsecured  indebtedness  would  exceed ten  percent  of the  aggregate
principal amount of all of SCE&G's secured indebtedness and capital and surplus;
however,  no such  consent is required to enter into  agreements  for payment of
principal,  interest and premium for  securities  issued for  pollution  control
purposes.

       Pursuant to Section 204 of the  Federal  Power Act,  SCE&G and GENCO must
obtain FERC authority to issue  short-term  debt.  FERC has authorized  SCE&G to
issue up to $250 million of unsecured  promissory notes or commercial paper with
maturity dates of 12 months or less, but not later than December 31, 2002. GENCO
has not sought such authorization.

        The SEC order  authorizing  the Company to register as a public  utility
holding company under PUHCA imposes various limits during the three years ending
February  11, 2003 (the  Authorization  Period) on  SCANA's,  SCE&G's and PSNC's
ability to issue long- and  short-term  debt.  The order,  as amended,  requires
SCANA,  SCE&G and PSNC to maintain common equity of at least 30 percent of their
consolidated  capitalization.  SCANA's issuance of capital securities is limited
to  $2.385  billion,  including  securities  issued  to repay  acquisition  debt
financing.  SCANA's  short-term  borrowings  outstanding  are  limited  to  $450
million.  SCE&G and PSNC may issue  commercial paper and establish bank lines of
credit for $300  million  and $200  million,  respectively.  In  addition,  PSNC
requires SEC approval under PUHCA prior to issuing long-term debt.
SCANA plans to request such approval for PSNC in 2001.

       At December 31, 2000 SCE&G had $250 million of unused authorized lines of
credit  which  consist of a credit  agreement  for a maximum of $250  million to
support the issuance of commercial paper.  SCE&G's  commercial paper outstanding
at  December  31,  2000  and  1999  was  $117.5  million  and  $143.1   million,
respectively.  In addition, Fuel Company has a credit agreement for a maximum of
$125  million with the full amount  available  at December 31, 2000.  The credit
agreement supports the issuance of short-term commercial paper for the financing
of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company
commercial  paper  outstanding  at  December  31, 2000 was $70.2  million.  This
commercial paper and amounts  outstanding  under the revolving credit agreement,
if any, are guaranteed by SCE&G.

       At December  31, 2000 PSNC had $125  million  authorized  lines of credit
which consist of a credit agreement for a maximum of $125 million to support the
issuance  of  commercial  paper.  Unused  lines of credit at  December  31, 2000
totaled $125 million.  PSNC's  commercial paper outstanding on December 31, 2000
was $125 million.

       SCE&G's  Restated   Articles  of  Incorporation   prohibit   issuance  of
additional  shares of  preferred  stock  without  the  consent of the  preferred
stockholders  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  (Preferred Stock Ratio).  For the year ended December 31, 2000 the
Preferred Stock Ratio was 2.09.

       As a result of SCANA's  acquisition  of PSNC on February 10,  2000,  PSNC
shareholders  were paid $212  million in cash and 17.4  million  shares of SCANA
common stock valued at  approximately  $488  million.  In  connection  with this
transaction,  certain SCANA shareholders were paid $488 million in cash for 16.3
million shares of SCANA common stock.  During 2000,  shares for the SPSP and the
Investor Plus Plan were purchased on the open market.

       The Company's ratios of earnings to fixed charges (SEC method) were 2.57,
2.98,  3.67,  3.64 and 3.60 for the years ended December 31, 2000,  1999,  1998,
1997 and 1996, respectively.  For SCE&G these ratios were 4.20, 3.71, 4.40, 3.85
and 3.80 for the same  periods.  For PSNC  these  ratios  were 2.97 for the year
ended December 31, 2000 and 3.24, 3.23, 3.44 and 3.62 for the fiscal years ended
September 30, 1999, 1998, 1997 and 1996, respectively.

ELECTRIC OPERATIONS

Electric Sales

         In 2000 residential sales of electricity  accounted for 40% of electric
sales revenues; commercial sales 30%; industrial sales 19%; sales for resale 3%;
and all other 8%. The Company's KWH sales by  classification,  excluding volumes
attributable to the cumulative effect of accounting  change, for the years ended
December 31, 2000 and 1999 are presented below:

                                            Sales
                                       KWH (Millions)
--------------------------------------------------------------------------------

                 CLASSIFICATION          2000      1999          % CHANGE
--------------------------------------------------------------------------------

Residential                              6,665         6,269         6%
Commercial                               6,305         5,950         6%
Industrial                               6,665         6,140         9%
Sales for resale                         1,222         1,189         3%
Other                                      553           518         7%
----------------------------------------------------------------
Total Territorial                       21,410        20,066         7%
Negotiated Market  Sales Tariff          1,942         1,678        16%
================================================================
Total                                   23,352       21,744          7%
================================================================

   Sales  for  resale   includes   electricity   furnished  for  resale  to  two
municipalities and two electric cooperatives.  Sales under the Negotiated Market
Sales  Tariff  during 2000  include  sales to 36  investor-owned  utilities  and
registered marketers,  seven electric cooperatives,  two municipalities and four
federal/state  electric agencies.  During 1999 sales under the Negotiated Market
Sales  Tariff  included  sales to 32  investor-owned  utilities  and  registered
marketers,   seven   electric   cooperatives,   two   municipalities   and  four
federal/state electric agencies.

         The electric  sales volume from  residential  sales  increased for 2000
primarily as a result of colder weather.  During 2000 the Company recorded a net
increase of 13,701  customers,  increasing its total  customers to 537,253.  The
all-time peak demand of 4,211 MW was set on July 20, 2000.

Electric Interconnections

         SCE&G  purchases all of the electric  generation  of Williams  Station,
owned by GENCO,  under a Unit Power Sales  Agreement  which has been approved by
FERC. Williams Station has a generating capacity of 580 MW.

         SCE&G's   transmission  system  is  part  of  the  interconnected  grid
extending over a large part of the southern and eastern  portions of the nation.
SCE&G,  Virginia  Power  Company,  Duke Power  Company,  Carolina  Power & Light
Company,  Yadkin,  Incorporated  and South  Carolina  Public  Service  Authority
(Santee Cooper) are members of the Virginia-Carolinas  Reliability Group, one of
several  geographic  divisions  within  the  Southeastern  Electric  Reliability
Council.  This Council provides for coordinated  planning for reliability  among
bulk power systems in the Southeast.  SCE&G is also  interconnected with Georgia
Power Company,  Savannah Electric & Power Company,  Oglethorpe Power Corporation
and the Southeastern Power Administration's Clark Hill Project.

         On February 9, 2000 the FERC issued FERC Order 2000. The Order requires
utilities which operate  electric  transmission  systems to submit plans for the
possible  formation  of an RTO.  On October  16,  2000 the Company and two other
southeastern  electric  utilities  filed a joint  request with FERC to establish
GridSouth Transco, LLC (GridSouth). When operational, GridSouth will function as
an  independent  transmission  company.  Initially,  the  three  utilities  will
continue to own their  respective  transmission  networks,  while GridSouth will
provide planning and operational  oversight of the electric  transmission  grid.
FERC gave provisional approval to GridSouth in March 2001. GridSouth is expected
to be operational by December 2001.

Fuel Costs

         The  following  table sets forth the average  cost of nuclear  fuel and
coal and the weighted  average cost of all fuels (including oil and natural gas)
used by the Company for the years 1998-2000.

                                      2000          1999        1998
                                      ----          ----        ----
Nuclear:

   Per million BTU                     $.46         $.46          $.46
Coal:
SCE&G
   Per ton                           $37.10       $39.37        $38.19

   Per million BTU                      1.48        1.57          1.50
GENCO
   Per ton                           $38.98       $41.46        $41.67

   Per million BTU                      1.51        1.61          1.63
Weighted Average Cost of All Fuels:
   Per million BTU                    $1.31        $1.32         $1.26



<PAGE>



Fuel Supply

         The following  table shows the sources and  approximate  percentages of
the  Company's  total  KWH  generation  by each  category  of fuel for the years
1998-2000 and the estimates for 2001 and 2002.

                                         Percent of Total KWH Generated
                  -------------------------------------------------------------
                        Estimated                        Actual
                  ----------------------   ------------------------------------
                    2002        2001         2000       1999       1998
                    ----        ----         ----       ----       ----

Coal                 67%        73%           77%        73%        69%
Nuclear              20         20            18         22         25
Hydro                 6          5             4          4          5
Natural Gas & Oil     7          2             1          1          1
                  ========== ============= ====================================
                    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,  2000  SCE&G  had  approximately  a 37-day  supply  of coal in
inventory and GENCO had approximately a 43-day supply.

         Coal is obtained  through  contracts  and purchases on the spot market.
Spot market  purchases are expected to continue for coal  requirements in excess
of those provided by SCANA's existing contracts.

         Contract  coal is  purchased  from ten  suppliers  located  in  eastern
Kentucky, Tennessee, southwest Virginia and West Virginia. Contract commitments,
which expire at various  times from 2001 through 2009,  approximate  6.1 million
tons  annually,  which is 88 percent of total  expected coal purchases for 2001.
Sulfur restrictions on the contract coal range from 0.75 percent to 1.5 percent.

         SCE&G is building two  combined-cycle  turbines  that will burn natural
gas to produce 300 megawatts of new electric  generation and use exhaust heat to
replace  coal-fired  steam that powers two existing 75 megawatt  turbines at the
Urquhart Generating Station.  The turbine project is schedule to be completed by
June 2002.

         The  Company  believes  that  SCE&G's  and  GENCO's  operations  are in
compliance  with all existing  regulations  relating to the  discharge of sulfur
dioxide and  nitrogen  oxides.  The Company is unaware  that any more  stringent
sulfur content  requirements  for existing plants are  contemplated at the state
level by DHEC.

         SCE&G has  adequate  supplies  of uranium or enriched  uranium  product
under contract to manufacture  nuclear fuel for Summer Station through 2005. The
following  table  summarizes all contract  commitments for the stages of nuclear
fuel assemblies:

                                                         Remaining   Expiration
Commitment           Contractor                          Regions(1)    Date

Enrichment     United States Enrichment Corporation (2)     16-18      2005
Fabrication    Westinghouse Electric Corporation            16-21      2009

(1)      A region represents  approximately one-third to one-half of the nuclear
         core in the reactor at any one time. Region 15 was loaded in 2001.
         Region 16 will be loaded in 2002.

(2)      Contract  provisions  for the  delivery  of  enriched  uranium  product
         encompass supply, conversion and enrichment services.

         SCE&G has on-site spent nuclear fuel storage  capability until at least
2006 and expects to be able to expand its storage  capacity to  accommodate  the
spent fuel output for the life of the plant through  spent fuel pool  reracking,
dry cask storage or other technology as it becomes available. In addition, there
is sufficient on-site storage capacity over the life of Summer Station to permit
storage of the entire reactor core in the event that complete  unloading  should
become  desirable or necessary for any reason.  (See Nuclear Fuel Disposal under
Environmental  Matters for  information  regarding the contract with the DOE for
disposal of spent fuel.)

         On October 7, 2000  Summer  Station  was  removed  from  service  for a
planned  maintenance  and refueling  outage.  See  preceding  discussion of this
matter on page 8.

Decommissioning

         For information  regarding the  decommissioning of Summer Station,  see
Note  1H,  Nuclear  Decommissioning,  of the  Notes  to  Consolidated  Financial
Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for
SCANA and SCE&G.

GAS OPERATIONS

Gas Sales - Regulated

         In 2000 the Company's  residential sales accounted for 38% of gas sales
revenues;  commercial sales 22%;  industrial sales 28%; sales for resale 8%; and
other 4%. During the same period, SCE&G's residential sales accounted for 41% of
gas sales revenues;  commercial sales 32%; and industrial sales 27%. Also during
the  same  period,  PSNC's  residential  sales  accounted  for 64% of gas  sales
revenues;  commercial  sales 27%; and industrial  sales 9%.  Dekatherm  sales by
classification,  excluding  volumes  associated  with the  cumulative  effect of
accounting  change, for the years ended December 31, 2000 and 1999 are presented
below:

<TABLE>

                                                           Sales
                                                     Dekatherms (000)
----------------------------------------------------------------------------------------------------------------------------
                                    The Company                           SCE&G                           PSNC
                                                      %                                %                             %
CLASSIFICATION            2000          1999*       Change      2000       1999      Change    2000       1999     Change
----------------------- ---------- ------------- ------------ ---------- --------- ---------- -------- --------- -----------

<S>                       <C>         <C>           <C>        <C>        <C>         <C>      <C>       <C>        <C>
Residential               35,365      11,823        199.1%     12,235     11,823      3.5%     23,130    19,976     15.8%
Commercial                25,039      11,790        112.4%     12,076     11,699      3.2%     12,850    11,609     10.7%

Industrial                61,662      61,748         (0.1%)    17,129     17,958     (4.6%)     5,307     6,349    (16.4%)

Sales for Resale          16,931      15,947          6.2%          -         -         -           -        -         -
Transportation gas        31,634       2,252      1,304.7%      2,085      1,975      5.6%     29,372    28,750      2.2%
                        --------   ----------                 -- -----   -------               ------    ------
       Total            170,631     103,560          64.8%     43,525     43,455      0.2%     70,659    66,684      6.0%
======================= ========== ============= ============ ========== ========= ========== ======== ========= ===========
*SCANA acquired PSNC effective January 1, 2000 for accounting purposes.  Therefore, the Company's 1999 sales do
  not include PSNC.
</TABLE>

         The Company's and SCE&G's gas sales volume increased for 2000 primarily
as a result of customer growth.  The Company obtained 354,763  customers when it
acquired PSNC. In addition,  during 2000 the Company  recorded a net increase of
21,798  customers,  increasing its total customers to 637,017.  SCE&G recorded a
net increase of 6,103 gas customers,  increasing its total customers to 266,348.
PSNC recorded a net increase of 15,148 customers, increasing its total customers
to 370,181.

         The demand for gas is affected by the weather,  the price  relationship
between gas and alternate fuels and other factors.

         Pipeline  Corporation,  operating  wholly  within  the  State  of South
Carolina,  provides  natural  gas utility and  transportation  services  for its
customers,  and supplies  natural gas to SCE&G and other  wholesale  purchasers.
Pipeline  Corporation is developing plans for an interstate natural gas pipeline
to ensure adequate supplies to growing gas markets.  The anticipated  interstate
pipeline will require  Pipeline  Corporation to file an application for approval
with FERC and other federal and state agencies.  Energy  Marketing  acquires and
sells natural gas in regulated and deregulated markets. Energy Marketing has not
supplied natural gas to any affiliate for use in providing regulated gas utility
services.


<PAGE>




Gas Cost and Supply

         Pipeline  Corporation   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 gas inventory
charge. The gas is brought to South Carolina through  transportation  agreements
with Southern Natural  (expiring in 2005 and 2006) and Transco (expiring in 2008
and 2017).  The daily  volume of gas that  Pipeline  Corporation  is entitled to
transport  under  these  contracts  on a firm  basis is 188 MMCF  from  Southern
Natural and 105 MMCF from Transco. Additional natural gas volumes are brought to
Pipeline  Corporation's  system  as  capacity  is  available  for  interruptible
transportation.  SCE&G, under contract with Pipeline Corporation, is entitled to
receive a daily contract demand of 266,495 dekatherms. The contract allows SCE&G
to receive amounts in excess of this demand based on availability.

         During 2000 Pipeline  Corporation's average cost per MCF of natural gas
purchased for resale,  including firm service demand charges, was $4.42 compared
to $2.99  during 1999.  SCE&G's  average cost per MCF was $5.35 and $3.73 during
2000 and 1999, respectively.

         Pipeline  Corporation has engaged in hedging activities on the New York
Mercantile  Exchange  (NYMEX) of its gas supply  pursuant  to a limited  program
authorized  and monitored by the PSC. Any gains or losses  associated  with that
hedging  activity are  accounted  for in Pipeline  Corporation's  purchased  gas
adjustment clause and, therefore, have no impact on net income.

         To meet the  requirements  of its high  priority  natural gas customers
during periods of maximum demand,  Pipeline Corporation supplements its supplies
of natural  gas from two LNG  plants.  The LNG plants are capable of storing the
liquefied  equivalent of 1,880 MMCF of natural gas.  Approximately 1,192 MMCF of
gas were in  storage  at  December  31,  2000.  On peak days the LNG  plants can
regasify  up to  150  MMCF  per  day.  Additionally,  Pipeline  Corporation  had
contracted for 6,447 MMCF of natural gas storage space. Approximately 3,713 MMCF
of gas were in storage on December 31, 2000.

        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 Gas  Transmission  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  dekatherms  from  Transco  and  30,331
dekatherms from Dominion Gas Transmission. PSNC Energy has submitted non-binding
nominations for firm transportation  service on three proposed pipeline projects
to meet incremental capacity requirements beginning in 2003.

        During 2000 PSNC  Energy's  average  cost per  dekatherm  of natural gas
purchased for resale,  including firm service demand charges, was $5.63 compared
to $3.71 during 1999.

        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 liquefied natural
gas (LNG) peaking services.  Underground  natural gas storage service agreements
with Dominion Gas  Transmission,  Columbia Gas  Transmission and Transco provide
for storage capacity of approximately 8,657 MMCF. In addition, PSNC Energy's own
LNG  facility is capable of storing the  liquefied  equivalent  of 1,000 MMCF of
natural gas with daily regasification  capability of 106 MMCF. Approximately 835
MMCF were in storage at December 31, 2000. LNG storage  service  agreements with
Transco, Cove Point LNG and Pine Needle LNG provide for approximately 1,266 MMCF
of storage  space.  At December 31, 2000  approximately  869 MMCF were stored in
these three facilities.

         The  Company  believes  that  supplies  under  long-term  contract  and
supplies  available  for spot market  purchase  are  adequate  to meet  existing
customer demands and to accommodate growth.

Curtailment Plans

         The PSC has established  allocation  priorities  applicable to the firm
and  interruptible  capacities of Pipeline  Corporation.  The  curtailment  plan
priorities of Pipeline Corporation apply to the resale distribution customers of
Pipeline Corporation, including SCE&G.

Gas Marketing - Nonregulated

         Energy Marketing markets natural gas and provides  energy-related  risk
management services to producers and consumers. Energy Marketing is also a power
marketer,  which allows it to buy and sell large blocks of electric  capacity in
wholesale  markets.  In addition,  SCANA Energy, a division of Energy Marketing,
markets natural gas to approximately  432,000 customers in Georgia's deregulated
natural gas market.

         Although  Energy  Marketing's  activities are primarily  focused in the
southeast,  Energy  Marketing has  maintained  smaller  scale  operations in the
Midwest and in California.  While Energy  Marketing has from time to time been a
customer of the California  utilities (PG&E,  SoCalEdison and SDG&E), it has not
been a supplier to such companies and does not have material  direct or indirect
credit risk related to them.

         The  Company's  Board of Directors has  established  a Risk  Management
Committee which is responsible for developing  corporate policies and overseeing
the management of risk within tolerance parameters approved by the Board.

REGULATION

General

         SCANA became a registered public utility holding company under PUHCA on
February 10, 2000,  concurrent with completion of its acquisition of PSNC. SCANA
and  its  subsidiaries  are  subject  to  the  jurisdiction  of  the  SEC  as to
financings, acquisitions and diversifications,  affiliate transactions and other
matters.

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

         Pipeline  Corporation is subject to the  jurisdiction  of the PSC as to
gas rates, service, accounting and other matters.

         PSNC is  subject  to the  jurisdiction  of the  NCUC  as to gas  rates,
issuance of securities (other than notes with a maturity of two years or less or
renewals of notes over a six-year or shorter  period),  service,  accounting and
other matters.

Federal Energy Regulatory Commission

         SCE&G and GENCO are subject to regulation  under the Federal Power Act,
administered  by FERC  and  DOE,  in the  transmission  of  electric  energy  in
interstate  commerce and in the sale of electric energy at wholesale for resale,
as well as with respect to licensed  hydroelectric  projects  and certain  other
matters, including accounting and the issuance of short-term promissory notes.
(See Capital Requirements and Financing Program.)

         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

Neal Shoals             2036       Saluda                         2007
Stevens Creek           2025       Parr Shoals                    2020
Columbia                2000       Fairfield Pumped Storage       2020

         SCE&G filed an  application  for a new license for Columbia on June 30,
1998. The  application  was officially  accepted for filing by FERC notice dated
December 23, 1999, and is currently in environmental review. The current license
for Columbia  expired on June 30, 2000;  subsequent to that date,  FERC issued a
temporary  operating  license to allow  SCE&G to continue to operate the project
until a new license is issued.


<PAGE>




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

         For a discussion of SCE&G's  agreement with FERC related to reinforcing
the Lake Murray Dam (related to the Saluda hydroelectric  project), see previous
discussion under Capital Requirements and see Liquidity and Capital Resources in
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations for SCANA and SCE&G.

Nuclear Regulatory Commission

         SCE&G  is  subject  to  regulation  by  the  NRC  with  respect  to the
ownership,   operation  and   decommissioning  of  Summer  Station.   The  NRC's
jurisdiction  encompasses  broad  supervisory  and  regulatory  powers  over the
construction and operation of nuclear reactors,  including matters of health and
safety,  antitrust  considerations  and environmental  impact. In addition,  the
Federal   Emergency   Management  Agency  is  responsible  for  the  review,  in
conjunction with the NRC, of certain aspects of emergency  planning  relating to
the operation of nuclear plants.

National Energy Policy Act of 1992 and FERC Orders No. 636,  888 and 2000

         The Company's  regulated business  operations were impacted by the NEPA
and FERC  Orders  No.  636,  888 and 2000.  NEPA was  designed  to create a more
competitive   wholesale  power  supply  market  by  creating  "exempt  wholesale
generators"  and  by  potentially   requiring   utilities  owning   transmission
facilities  to provide  transmission  access to  wholesalers.  Order No. 636 was
intended  to  deregulate  the  markets  for  interstate  sales of natural gas by
requiring  that  pipelines  provide  transportation  services  that are equal in
quality  for all gas  suppliers  whether  the  customer  purchases  gas from the
pipeline or another  supplier.  Orders No. 888 and 2000 require  utilities under
FERC  jurisdiction  that own,  control  or  operate  transmission  lines to file
nondiscriminatory open access tariffs that offer to others the same transmission
service  they  provide  to  themselves  and to  submit  plans  for the  possible
formation  of an RTO. The Company  believes it will  continue to be able to meet
successfully  the  challenges  of these altered  business  climates and does not
anticipate  there will be any material  adverse  impact from these Orders on the
Company's  results of  operations,  cash flows,  financial  position or business
prospects.

RATE MATTERS

         For a discussion of the impact of various rate matters,  see Regulatory
Matters  in  the  Liquidity  and  Capital   Resources  section  of  Management's
Discussion  and Analysis of Financial  Condition and Results of  Operations  for
SCANA and SCE&G, and the Notes to Consolidated Financial Statements appearing in
Item 8, FINANCIAL  STATEMENTS AND  SUPPLEMENTARY  DATA for SCANA (Note 4), SCE&G
(Note 3) and PSNC (Note 5).

General

         SCE&G and PSNC's gas rate  schedules  for their  residential  and small
commercial  customers include a WNA. SCE&G's and PSNC's WNA were approved by the
PSC and NCUC,  respectively,  and are in effect  for bills  rendered  during the
period  from  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 PSC has established a fuel cost recovery procedure which determines the
fuel component in SCE&G's retail electric base rates annually based on projected
fuel costs for the ensuing 12-month period,  adjusted for any  overcollection or
undercollection  from the  preceding  12-month  period.  SCE&G  has the right to
request a formal  proceeding  at any time should  circumstances  dictate  such a
review.  In the April 2000 annual review of the fuel cost  component of electric
rates,  the PSC decreased the fuel cost  component of the electric rate to 13.30
mills per KWH. For the April 2001 annual review, SCE&G has filed for an increase
in the fuel cost component of electric rates to 15.79 mills per KWH.


<PAGE>




         SCE&G's gas rate schedules and contracts include  mechanisms that allow
it to recover from its customers changes in the actual cost of gas. SCE&G's firm
gas rates allow for the recovery of a fixed cost of gas,  based on  projections,
as established by the PSC 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.  In
July 2000 the PSC approved  SCE&G's request for an  out-of-period  adjustment to
increase the cost of gas  component  from 54.334 cents per therm to 68.835 cents
per therm, effective with the first billing cycle in August 2000. In the October
2000 review the PSC increased the base cost of gas to 78.151 cents per therm. In
December 2000 the PSC approved SCE&G's request for an  out-of-period  adjustment
to increase the cost of gas component to 99.340 cents per therm,  effective with
the first billing cycle in January 2001. In March 2001 the PSC approved  SCE&G's
request  to  decrease  the cost of gas  component  to 79.340  cents  per  therm,
effective with the first billing cycle in March 2001.

         PSNC also  operates  under two rate  provisions in addition to WNA that
serve to  reduce  fluctuations  in  PSNC's  earnings.  First,  its  Rider D rate
mechanism allows PSNC to recover,  in any manner  authorized by the NCUC, margin
losses on negotiated  gas sales.  The Rider D rate mechanism also allows PSNC to
recover from customers all prudently  incurred gas costs,  including  changes in
natural gas prices. Second, PSNC operates with full margin transportation rates.
These  rates allow PSNC to earn the same margin on gas  delivered  to  customers
regardless  of  whether  the gas is sold,  or only  transported,  by PSNC to the
customer.

         PSNC's rates are  established  using a base cost of gas approved by the
NCUC, which may be modified  periodically to reflect changes in the market price
of natural gas and changes in the rates charged by PSNC's pipeline transporters.
PSNC may file revised  tariffs with the NCUC coincident with these changes or it
may  track  the  changes  in  its   deferred   accounts  for   subsequent   rate
consideration. The NCUC reviews PSNC's gas purchasing practices annually.

ENVIRONMENTAL MATTERS

General

         Federal and state  authorities have imposed  environmental  regulations
and standards  relating  primarily to air emissions,  wastewater  discharges and
solid,  toxic and hazardous  waste  management.  Developments in these areas may
require that equipment and facilities be modified, supplemented or replaced. The
ultimate  effect of these  regulations  and standards upon existing and proposed
operations  cannot be  forecast.  For a more  complete  discussion  of how these
regulations and standards  impact the Company and SCE&G,  see the  Environmental
Matters section of Management's  Discussion and Analysis of Financial  Condition
and Results of Operations for SCANA and SCE&G.

Capital Expenditures

         In the years 1998 through 2000, the Company's capital  expenditures for
environmental   control  amounted  to  approximately  $98.4  million  (including
approximately  $88.1  million for SCE&G).  This was in addition to  expenditures
included in "Other operation and maintenance" expenses, which were approximately
$19.6  million,  $18.2 million,  and $18.8 million  during 2000,  1999 and 1998,
respectively  (including  approximately  $16.6 million,  $15.0 million and $16.2
million for SCE&G during 2000, 1999 and 1998, respectively).  It is not possible
to estimate all future  costs for  environmental  purposes,  but  forecasts  for
capitalized  environmental  expenditures  for the Company are $23.3  million for
2001 and $192.8  million for the four-year  period 2002 through 2005  (including
$22.8 million for 2001 and $129.4 million for the four-year  period 2002 through
2005 for SCE&G).  These  expenditures  are included in the Company's and SCE&G's
construction program.

         In  October  1998 the EPA  issued a final  rule  requiring  22  states,
including South Carolina,  to modify their state  implementation  plans (SIP) to
address  the issue of NOx  pollution.  On May 25, 1999 a federal  appeals  court
delayed  indefinitely the implementation of the rule. On March 3, 2000 the court
affirmed  the  EPA's  NOx rule  for the  affected  states.  South  Carolina  was
subsequently  ordered to amend its SIP to achieve  significant  NOx  reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and the
EPA has issued  official notice to South Carolina (and a number of other states)
to comply.  While not final,  South  Carolina has proposed NOx  reductions  that
would require the Company to install pollution control  equipment.  Because DHEC
had not amended its SIP as of December  31, 2000 to set out or allocate  any NOx
reductions,  it is not possible to estimate what, if any,  capital  expenditures
will be required to comply with any potential mandated reductions.



<PAGE>



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 on June 29, 1983  providing
for  permanent  disposal of its spent nuclear fuel by the DOE. The DOE presently
estimates that the permanent  storage facility will not be available until 2010.
SCE&G has on-site spent nuclear fuel storage  capability until at least 2006 and
expects to be able to expand  its  storage  capacity  to  accommodate  the spent
nuclear fuel output for the life of the plant through spent fuel pool reracking,
dry cask  storage  or other  technology  as it becomes  available.  The Act also
imposes on  utilities  the  primary  responsibility  for  storage of their spent
nuclear fuel until the repository is available.

OTHER MATTERS

         With regard to SCE&G's insurance coverage for Summer Station, reference
is made to the  Notes to  Consolidated  Financial  Statements  (Note 13B for the
Company and Note 12B for SCE&G), which are incorporated herein by reference.

         For  a   description   of  the   Company's   investments   in   various
telecommunications  companies,  see Other in the Liquidity and Capital Resources
section of  Management's  Discussion  and  Analysis of Financial  Condition  and
Results of Operations for SCANA.

ITEM 2. PROPERTIES

         SCANA owns no significant property other than the capital stock of each
of its subsidiaries.  It holds, directly or indirectly, all of the capital stock
of each of its  subsidiaries  except  for the  preferred  stock  of  SCE&G,  the
preferred  securities of SCE&G Trust I and 30 percent of an indirect subsidiary.
It also has  investments in two LLCs:  one operates a  cogeneration  facility in
Charleston,  South Carolina and the other operates a lime production facility in
Charleston, South Carolina.

         SCE&G's  bond  indentures,  securing the First and  Refunding  Mortgage
Bonds and First Mortgage Bonds issued  thereunder,  constitute  direct  mortgage
liens on substantially all of its property.  GENCO's Williams Station is subject
to a first mortgage lien.

         For a  brief  description  of the  properties  of the  Company's  other
subsidiaries,  which are not  significant  as defined in Rule 1-02 of Regulation
S-X, see Item 1, BUSINESS-SEGMENTS OF BUSINESS-Nonregulated Businesses.


<PAGE>



ELECTRIC

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

                                                                  Net Generating
                   Present                            Year          Capacity
    Facility    Fuel Capability  Location          In-Service   (Summer Rating)
                                                                           (KW)

    Steam
    -----
    Urquhar(1)      Coal/Gas   Beech Island, SC       1953        250,000
    McMeekin        Coal/Gas   Irmo, SC               1958        252,000
    Canadys         Coal/Gas   Canadys, SC            1962        420,000
    Wateree         Coal       Eastover, SC           1970        700,000
    Williams(2)     Coal       Goose Creek, SC        1973        615,000
    Summer(3)       Nuclear    Parr, SC               1984        635,000
    D-Area(4)       Coal       DOE Savannah River
                                Site, SC              1995         38,000
    Cope            Coal       Cope, SC               1996        417,000
    Cogen South       *        Charleston, SC         1999         65,000
    Gas Turbines
    ------------
    Burton          Gas/Oil    Burton, SC             1961         28,500
    Faber Place     Gas        Charleston, SC         1961          9,500
    Hardeeville     Oil        Hardeeville, SC        1968         14,000
    Urquhart        Gas/Oil    Beech Island, SC       1969         38,000
    Coit            Gas/Oil    Columbia, SC           1969         30,000
    Parr            Gas/Oil    Parr, SC               1970         60,000
    Williams        Gas/Oil    Goose Creek, SC        1972         49,000
    Hagood          Gas/Oil    Charleston, SC         1991         95,000
    Urquhart #4     Gas/Oil    Beech Island, SC       1999         48,000
    Hydro
    -----
    Neal Shoals                Carlisle, SC           1905          5,000
    Parr Shoals                Parr, SC               1914         14,000
    Stevens Creek              Martinez, GA           1914          9,000
    Columbia                   Columbia, SC           1927         10,000
    Saluda                     Irmo, SC               1930        206,000
    Pumped Storage
    --------------
    Fairfield                  Parr, SC               1978        536,000
                                                               ----------
                                                                4,544,000

(1)      On  September  21,  1999 SCE&G  announced  a $256  million  gas turbine
         generator project in Aiken County,  South Carolina.  Two combined-cycle
         turbines will burn natural gas to produce 300 megawatts of new electric
         generation and use exhaust heat to replace coal-fired steam that powers
         two existing 75 megawatt turbines at the Urquhart  Generating  Station.
         The turbine project is scheduled to be completed by June 2002.
(2) The steam unit at Williams Station is owned by GENCO. (3) Represents SCE&G's
two-thirds portion of the Summer Station.  (4) This plant is leased from the DOE
and is dedicated to DOE's Savannah
         River Site steam needs.  "Net Generating  Capability" for this plant is
         expected average hourly output. The lease expires on October 1, 2005.

* SCE&G  receives  shaft horse power from Cogen  South,  LLC to operate  SCE&G's
generator.  Cogen  South,  LLC is owned 50  percent  by SCANA and 50  percent by
Westvaco.

         SCE&G owns 450 substations having an aggregate  transformer capacity of
22,673,443 KVA. The transmission system consists of 3,166 miles of lines and the
distribution  system  consists of 16,778 pole miles of overhead  lines and 3,836
trench miles of underground lines.



<PAGE>



GAS

Natural Gas

         SCE&G's  gas  system   consists  of   approximately   12,596  miles  of
distribution mains and related service facilities.

         SCE&G also has propane air peak shaving facilities which can supplement
the supply of natural gas by  gasifying  propane to yield the  equivalent  of 73
MMCF per day.  These  facilities can store the equivalent of 392 MMCF of natural
gas.

         Pipeline Corporation's gas system consists of approximately 1,947 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.

         Pipeline  Corporation owns two LNG plants, one located near Charleston,
South Carolina and the other in Salley, South Carolina.  The Charleston facility
can liquefy up to 6 MMCF per day and store the liquefied  equivalent of 980 MMCF
of natural gas. The Salley  facility can store the  liquefied  equivalent of 900
MMCF of  natural  gas and has no  liquefying  capabilities.  On peak  days,  the
Charleston  facility can regasify up to 60 MMCF per day and the Salley  facility
can regasify up to 90 MMCF.

         PSNC's gas system consists of  approximately  785 miles of transmission
pipeline of up to 24 inches in diameter  that connect its  distribution  systems
with Transco.  PSNC's  distribution system consists of approximately 7,049 miles
of distribution mains and related service facilities.  PSNC also owns, through a
wholly owned subsidiary,  33.21 percent of Cardinal Pipeline Company, LLC, which
owns a 105-mile transmission pipeline. In addition,  PSNC owns, through a wholly
owned subsidiary,  17 percent of Pine Needle LNG Company,  LLC. Pine Needle owns
and operates a liquefaction, storage and regasification facility.

TRANSIT

         SCE&G  owns 40 motor  coaches  used in the  operation  of the  Columbia
transit  system.  The Columbia  system is  comprised  of 17 routes  covering 177
miles. SCE&G intends to dispose of its investment in the Columbia transit system
as soon as practicable.  Management is uncertain as to what the costs associated
with the disposition of the transit system will be.

ITEM 3.  LEGAL PROCEEDINGS

         For information regarding legal proceedings,  see Item 1, BUSINESS RATE
MATTERS (the Company,  SCE&G and PSNC),  Environmental  Matters in the Liquidity
and Capital Resources section of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (the Company and SCE&G), and Notes
to Consolidated  Financial  Statements appearing in Item 8, FINANCIAL STATEMENTS
AND SUPPLEMENTARY  DATA (Note 13C and 13E for the Company,  Note 12C and 12E for
SCE&G and Note 12 for PSNC).

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

           Not Applicable



<PAGE>


<TABLE>


     CORPORATE STRUCTURE

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

<S>                                             <C>
  SOUTH CAROLINA ELECTRIC & GAS COMPANY         SCANA COMMUNICATIONS, INC.
  -------------------------                    --------------------------
  Generates   and   sells    electricity    and   gas   Provides   fiber   optic
  telecommunications to wholesale and retail customers, in South Carolina, tower
  construction,  purchases,  sells and transports management and rental services
  for natural  gas at retail and  provides  wireless  providers  and,  through a
  public tansit service in Columbia. subsidiary, invests in telecommunications
                                                companies.

                          SCANA ENERGY MARKETING, INC.
  SOUTH CAROLINA GENERATING                     Markets electricity, natural gas and
  COMPANY, INC.                                 other light hydrocarbons primarily in
  Owns and operates Williams Station and        the southeast.  Provides energy-related risk
  sells electricity to SCE&G.                   management services to producers and customers.
  Through its SCANA Energy division, markets
  SOUTH CAROLINA FUEL                           natural gas in Georgia's deregulated retail natural
  COMPANY, INC.                                 gas market.
  Acquires, owns and provides financing
  for SCE&G's nuclear fuel, fossil fuel         SERVICECARE, INC.
  and sulfur dioxide emission allowances.       Provides energy-related products and
                      service contracts on home appliances.
  SOUTH CAROLINA PIPELINE
  CORPORATION                                   PRIMESOUTH, INC.
  Purchases, sells and transports natural       Engages in power plant management and
  gas to wholesale and direct industrial        maintenance services.
  customers.  Owns and operates two LNG
  plants for the liquefaction, storage and      SCANA RESOURCES, INC.
  regasification of natural gas.                Conducts energy-related businesses and provides
                                                energy-related services.
  PUBLIC SERVICE COMPANY OF
  NORTH  CAROLINA,  INCORPORATED  SCANA  SERVICES,  INC.  Purchases,  sells  and
  transports natural gas Provides administrative, management and other to retail
  customers,  markets  natural gas,  services to the  subsidiaries  and business
  units  refuels  natural gas vehicles and within  SCANA  Corporation.  converts
  gasoline-fueled vehicles to natural gas.

</TABLE>








     Each of the above listed companies is organized and incorporated  under the
     laws of the  State of South  Carolina.  SCANA  also  owns  four  additional
     companies that are in liquidation.


<PAGE>







                     EXECUTIVE OFFICERS OF SCANA CORPORATION

  The executive officers are elected at the annual organizational meeting of the
Board of Directors,  held immediately  after the annual meeting of stockholders,
and hold office until the next such organizational meeting, unless a resignation
is submitted, or unless the Board of Directors shall otherwise determine.

<TABLE>

                                  Positions Held During
    Name                 Age      Past Five Years                                                   Dates

<S>                       <C>                                                                       <C>
    W. B. Timmerman       54      Chairman of the Board and Chief Executive Officer                 1997-present
                                  Chief Operating Officer                                           1996-1997
                                  President                                                         *-present
                                  President, SCI                                                    1996-1997
                                  Chief Financial Officer and Controller                            *-1996

    H. T. Arthur          55      Senior Vice President and General Counsel                         1998-present
                                  Vice President and General Counsel                                1996-1998
                                  Vice President and General Counsel, Pipeline Corporation          *-1996

    G. J. Bullwinkel      52      Senior Vice President, Governmental Affairs and
                                    Economic Development                                            1999-present
                                  President, SCI                                                    1997-present
                                  Senior Vice President - Retail Electric, SCE&G                    *-1999

    A. H. Gibbes          54      President and Chief Operating Officer, Pipeline Corporation       1996-present
                                  Senior Vice President and General Counsel                         *-1996
                                  President and Treasurer, SCANA Development Corp.                  *-present

    D. C. Harris          48      Senior Vice President of Human Resources - SCANA                  2000-present
                                  Vice President Human Resources, Austin Quality Foods,
                                    Inc., Cary, NC                                                  *-2000

    N. O. Lorick          50      President and  Chief Operating Officer, SCE&G                     2000-present
                                  Vice President of Fossil and Hydro Operations                     *-2000

    K. B. Marsh           45      Senior Vice President - Finance and  Chief Financial Officer      2000-present
                                  Senior Vice President - Finance, Chief Financial Officer
                                    and Controller                                                  1998-2000
                                  Vice President - Finance, Chief Financial Officer and Controller  1996-1998
                                  Vice President - Finance, Treasurer and Secretary                 *-1996

    A. M. Milligan        41      Senior Vice President - Marketing                                 1998-present
                                  Director of Consumer Credit Marketing,
                                    Barnett Bank, N. A., FL                                         1996-1998
                                  Senior Vice President - Marketing, Barnett Card Services, FL      *-1996

    C. E. Zeigler, Jr.    54      President and Chief Operating Officer of PSNC                     2000-present
                                  Chairman, President and Chief Executive Officer                   *-2000
                                    of PSNC (prior to acquisition)

    S. A. Byrne           40      Vice President Nuclear Operations                                 2000-present
                                  General Manager Nuclear Plant Operations                          *-2000

    M. R. Cannon          50      Controller, SCANA and all subsidiaries (excluding SEMI)           2000-present
                                  Treasurer, SCANA and SCE&G                                        *-2000

</TABLE>

    * Indicates position held at least since March 1, 1996.





<PAGE>


<TABLE>

                                     PART II

   ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
             MATTERS

   COMMON STOCK INFORMATION - SCANA Corporation
-------------------- ---------------------------------------------------- ----------------------------------------------------
                                              2000                                                 1999
-------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------
                        4th                                      1st
                        Qtr.        3rd Qtr.      2nd Qtr.       Qtr.        4th Qtr.     3rd Qtr.     2nd Qtr.      1st Qtr.
-------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------

   Price Range: (a)
<S>                       <C>        <C>            <C>          <C>         <C>          <C>            <C>          <C>
       High               31.13      30.94          26.88        29.00       28.31        25.69          26.94        32.56
       Low                25.75      24.38          22.81        22.00       23.63        22.81          21.13        21.56
-------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------
   (a)  As reported on the New York Stock Exchange Composite Listing.



------------------------------ -------------------- ------------------- ------------ -------------------- -----------------
      Dividends Per Share               2000                                                  1999
------------------------------ -------------------- -------------------              -------------------- -----------------
                                                                        ------------
                      Amount       Date Declared          Date Paid         Amount       Date Declared         Date Paid
                      ------       -------------          ---------         ------       -------------         ---------
<S>                    <C>                <C> <C>            <C>            <C>               <C>                 <C>
   First Quarter       .2875     February 22, 2000     April 1, 2000        .3850       March 9, 1999       April 1, 1999
   Second Quarter      .2875       April 27, 2000       July 1, 2000        .3850       June 9, 1999        July 1, 1999
   Third Quarter       .2875      August 16, 2000      October 1, 2000      .2750      September 10,1999    October 1, 1999
   Fourth Quarter      .2875      October 17, 2000     January 1, 2001      .2750      December 10,1999       January 1,2000
------------------ ----------- -------------------- ------------------- ------------ -------------------- -----------------
</TABLE>

   The principal  market for SCANA common stock is the New York Stock  Exchange.
   The ticker symbol used is SCG. The corporate  name SCANA is used in newspaper
   stock listings.  The total number of shares of SCANA common stock outstanding
   at February 28, 2001 was  104,729,131.  The number of common  stockholders of
   record at February 28, 2001 was 43,245.

   All of SCE&G and  PSNC's  common  stock is owned by SCANA and has no  market.
   During  2000  and  1999  SCE&G  paid  $130.8  million  and  $122.4   million,
   respectively,  in cash  dividends  to SCANA.  During  2000,  PSNC paid  $19.0
   million in cash dividends to SCANA.

   SECURITIES RATINGS (As of February 28, 2001)
<TABLE>
         SCANA                                            SCE&G                                          PSNC
---------------------- ---------------------------- ---------------------------------------------- -- ----------------------
                                           First and

             Medium-         First         Refunding                   Trust
<S>            <C>         <C>             <C>          <C>           <C>          <C>              <C>           <C>
   Rating      Term         Mortgage       Mortgage      Preferred    Preferred    Commercial        Senior       Commercial

   Agency     Notes          Bonds           Bonds        Stock       Securities      Paper        Unsecured        Paper
   ------     -----          -----           -----        -----       ----------      -----        ---------        -----


   Fitch
   IBCA,

   Duff
   &
   Phelps       A-              A+              A+          A            A             F-1            n/a            n/a

   Moody's      A3              A1              A1          a2           a2            P-1             A2            P-1

   Standar
   &            A-
   Poors  d                    A               A            BBB+         BBB+          A-1             A             A-1
--------- ------------ ---------------- ------------- ------------ ------------ --------------- -------------- -------------
</TABLE>

   Further reference is made to the Notes to Consolidated  Financial  Statements
   appearing in Item 8, FINANCIAL  STATEMENTS AND  SUPPLEMENTARY  DATA for SCANA
   (Note 6), SCE&G (Note 5) and PSNC (Note 7).

       The  Restated  Articles  of  Incorporation  of  SCE&G  and the  Indenture
   underlying its First and Refunding  Mortgage Bonds contain  provisions  that,
   under  certain  circumstances,  could limit the payment of cash  dividends on
   common  stock.  In addition,  with  respect to  hydroelectric  projects,  the
   Federal Power Act requires the appropriation of a portion of certain earnings
   therefrom.  At December  31,  2000  approximately  $32.7  million of retained
   earnings were restricted by this  requirement as to payment of cash dividends
   on common stock of SCE&G.


<PAGE>
<TABLE>

ITEM 6.  SELECTED FINANCIAL DATA
                                                                                  SCANA
------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- ---

For the Years Ended December 31,                         2000(1)        1999     1998           1997    1996
------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- ---

Statement of Income Data
<S>                                                       <C>         <C>          <C>        <C>        <C>
  Operating Revenues                                      $3,433      $2,078       $2,106     $1,725     $1,510
  Operating Income                                           554         353          470        425        442
  Other Income (Loss)                                         44          90           19         41         20
  Income Before Cumulative Effect of Accounting
Change                                                       221         179          223        221        215
  Net Income                                                 250         179          223        221        215

Balance Sheet Data
  Utility Plant, Net                                      $4,949      $3,851       $3,787     $3,648     $3,529
  Total Assets                                             7,420       6,011        5,281      4,932      4,759

  Capitalization:
      Common equity                                        2,032       2,099        1,746      1,788      1,684
      Preferred Stock (Not subject to purchase or
sinking funds)                                               106         106          106        106         26
      Preferred Stock (Subject to purchase or
sinking funds)                                                10          11           11         12         43
      SCE&G  - Obligated Mandatorily Redeemable
Preferred
        Securities of SCE&G's Subsidiary, SCE&G
Trust I,
        Holding Solely $50 million Principal Amount
of  7.55%
        Junior Subordinated Debentures of  SCE&G,
due 2027                                                      50          50           50         50      -
      Long-term Debt, net                                  2,850       1,563        1,623      1,566      1,581
------------------------------------------------------ ---------- ----------- ------------ ---------- ----------
====================================================== ========== =========== ============ ==========            ---
 Total Capitalization                                     $5,048      $3,829       $3,536     $3,522     $3,334
====================================================== ========== =========== ============ ========== ========== ---
Common Stock Data
  Weighted Average Number of Common Shares
     Outstanding (Millions)                                104.5       103.6        105.3      107.1      105.1
   Basic and Diluted Earnings Per  Share                   $2.40       $1.73        $2.12      $2.06      $2.05
   Dividends Declared Per Share of Common Stock            $1.15       $1.32        $1.54      $1.51      $1.47
Other Statistics (2)
   Electric:
      Customers (Year-End)                               537,253     523,552      517,447    503,905    493,320
      Total sales (Million KWH)                           23,352      21,744       21,203     18,852     18,905
      Residential:
         Average annual use per customer (KWH)            14,596      14,011       14,481     13,214     14,149
         Average annual rate per KWH                      $.0787      $.0787       $.0801     $.0799     $.0785
      Generating capability - Net MW (Year-End)            4,544       4,483        4,387      4,350      4,316
      Territorial peak demand - Net MW                     4,211       4,158        3,935      3,734      3,698
   Regulated Gas:
      Customers (Year-End)                               637,017     260,456      257,051    252,797    248,787
      Sales, excluding transportation (Thousand
Therms)                                                1,389,975   1,013,083    1,002,952    945,289    893,170
      Residential:
         Average annual use per customer (Therms)            644         507          521        531        639
         Average annual rate per therm                     $1.08        $.86         $.86       $.86       $.74
   Nonregulated Gas:
      Retail customers (Year-End)                        431,814     430,950       78,091        n/a        n/a
      Firm customer deliveries (Thousand Therms)         431,115     229,660        4,692        n/a        n/a
      Interruptible customer deliveries (Thousand
Therms)                                                  306,099     188,828    2,167,931        n/a        n/a



<PAGE>




                                                                               SCE&G
------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
For the Years Ended December 31,                           2000       1999       1998       1997       1996
------------------------------------------------------ ---------- ---------- ---------- ---------- ----------

Statement of Income Data
<S>                                                       <C>        <C>        <C>        <C>        <C>
  Operating Revenues                                      $1,669     $1,465     $1,450     $1,337     $1,341
  Operating Income                                           457        393        448        387        404
  Other Income (Loss)                                         16         12          9          5        (6)
  Income Before Cumulative Effect of Accounting
Change                                                       231        189        227        195        190
  Net Income                                                 253        189        227        195        190

Balance Sheet Data
  Utility Plant, Net                                      $3,615     $3,501     $3,432     $3,310     $3,197
  Total Assets                                             4,664      4,404      4,246      4,054      3,959

  Capitalization:
      Common equity                                        1,657      1,558      1,499      1,447      1,413
      Preferred Stock (Not subject to purchase or
sinking funds)                                               106        106        106        106         26
      Preferred Stock (Subject to purchase or
sinking funds)                                                10         11         11         12         43
      SCE&G  - Obligated Mandatorily Redeemable
Preferred
        Securities of SCE&G's Subsidiary, SCE&G
Trust I,
        Holding Solely $50 million Principal Amount
of  7.55%
        Junior Subordinated Debentures of  SCE&G,
due 2027                                                      50         50         50         50          -
      Long-term Debt, net                                  1,267      1,121      1,206      1,262      1,277
------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
====================================================== ========== ========== ========== ========== ==========
 Total Capitalization                                     $3,090     $2,846     $2,872     $2,877     $2,759
====================================================== ========== ========== ========== ========== ==========
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 Per  Share                     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
Other Statistics (2)
   Electric:
      Customers (Year-End)                               537,286    523,581    517,472    503,930    493,346
      Total sales (Million KWH)                           23,353     21,746     21,204     18,853     18,907
      Residential:
         Average annual use per customer (KWH)            14,596     14,011     14,481     13,214     14,149
         Average annual rate per KWH                      $.0787     $.0787     $.0801     $.0799     $.0785
      Generating capability - Net MW (Year-End)            3,929      3,883      3,807      3,790      3,756
      Territorial peak demand - Net MW                     4,216      4,158      3,935      3,734      3,698
   Regulated Gas:
      Customers (Year-End)                               266,451    260,348    256,843    252,589    248,497
      Sales, excluding transportation (Thousand
Therms)                                                  414,405   414, 800    405,249    381,726    387,328
      Residential:

         Average annual use per customer (Therms)            563        507        521        531        639
         Average annual rate per therm                      $.95       $.86       $.86       $.86      $ .74
   Nonregulated Gas:
      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
      Interruptible customer deliveries (Thousand
Therms)                                                      n/a        n/a        n/a        n/a        n/a


</TABLE>



<PAGE>






















                                SCANA CORPORATION









Item 7.       Management's Discussion and Analysis of Financial Condition
                  and Results of Operations................................  26

Item 7A.      Quantitative Disclosures About Market Risk...................  41

Item 8.       Financial Statements and Supplementary Data..................  42



<PAGE>



ITEM 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
                         RESULTS OF OPERATIONS

        Statements  included in this  discussion  and analysis (or  elsewhere in
this annual report) which are not statements of historical  fact are intended to
be, and are hereby identified as,  "forward-looking  statements" for purposes of
the safe  harbor  provided  by Section  27A of the  Securities  Act of 1933,  as
amended,  and Section 21E of the  Securities  Exchange Act of 1934,  as amended.
Readers  are  cautioned  that  any  such  forward-looking   statements  are  not
guarantees   of  future   performance   and   involve  a  number  of  risks  and
uncertainties,  and that  actual  results  could  differ  materially  from those
indicated by such forward-looking statements. Important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements  include,  but are not  limited  to,  the  following:  (1)  that  the
information  is of a  preliminary  nature and may be  subject to further  and/or
continuing  review  and  adjustment,  (2)  changes  in  the  utility  regulatory
environment,  (3)  changes in the  economy,  especially  in areas  served by the
Company's  subsidiaries  , (4) the  impact  of  competition  from  other  energy
suppliers,  (5) growth opportunities for the Company's regulated and diversified
subsidiaries, (6) the results of financing efforts, (7) changes in the Company's
accounting policies,  (8) weather conditions,  especially in areas served by the
Company's  subsidiaries , (9) performance of and  marketability of the Company's
investments in  telecommunications  companies,  (10) inflation,  (11) changes in
environmental  regulations and (12) the other risks and uncertainties  described
from time to time in the  Company's  periodic  reports  filed with the SEC.  The
Company disclaims any obligation to update any forward-looking statements.

COMPETITION

Regulated Electric and Gas Markets

        Efforts to restructure  electric  markets at the state level have slowed
considerably.  Dwindling  operating  reserves and rolling  blackouts in parts of
California  in January and February 2001 have been widely  reported  nationwide.
These   shortages  of   electricity   have  been   attributed  to  flawed  state
restructuring  legislation,  unplanned  generating  plant  shutdowns  and  other
economic  factors.  In  response,  many  states  that had  passed or  considered
legislation  to restructure  the electric  industry have stopped such efforts or
are proceeding more slowly.

        In South Carolina, electric restructuring efforts also have stalled. The
developments unfolding in California, and several unrelated,  contentious issues
before the General  Assembly  have  combined to make  consideration  of electric
restructuring  legislation unlikely in 2001. Legislation or regulatory action at
the Federal level,  particularly as a part of a larger energy policy initiative,
may be  considered  in 2001.  The  Company  is not able to predict  whether  any
restructuring  legislation  or regulatory  action will be enacted and, if it is,
the conditions it will impose on utilities.

        The  Company  has taken  several  steps to  prepare  for  restructuring,
including  aggressive  participation in the newly deregulated natural gas market
in Georgia (further  discussed at Georgia Retail Gas Market below). In addition,
SCANA's electric and gas utility, SCE&G, has undertaken a variety of initiatives
aimed at preparing for a restructured electric market. These initiatives include
obtaining accelerated recovery of electric regulatory assets,  establishing open
access  transmission  tariffs and selling bulk power to  wholesale  customers at
market-based rates. Marketing of services to commercial and industrial customers
has also increased significantly,  and SCE&G has obtained long term power supply
contracts with a significant  portion of its industrial  customers.  The Company
believes that these actions,  as well as numerous others that have been and will
be taken,  demonstrate  its ability and  commitment  to succeed in the  evolving
operating environment.

     Regulated  public utilities are allowed to record as assets some costs that
would be expensed by other enterprises.  If deregulation or other changes in the
regulatory  environment  occur,  the  Company may no longer be eligible to apply
this  accounting  treatment  and may be required to  eliminate  such  regulatory
assets from its balance sheet.  Although the potential  effects of  deregulation
cannot be determined at present,  discontinuation  of the  accounting  treatment
could have a material  adverse effect on the Company's  results of operations in
the period the write-off  would be recorded.  It is expected that cash flows and
the financial  position of the Company  would not be materially  affected by the
discontinuation of the accounting treatment.  The Company reported approximately
$244 million and $75 million of regulatory assets and liabilities, respectively,
including  amounts  recorded for deferred  income tax assets and  liabilities of
approximately $140 million and $57 million,  respectively,  on its balance sheet
at December 31, 2000.



<PAGE>



        The Company's  generation  assets are 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,
2000 the Company's net investment in fossil/hydro and nuclear  generation assets
was $1,332.6 million and $587.2 million, respectively.

North Carolina Gas Market

         On February 10, 2000 SCANA  completed its acquisition of Public Service
Company of North Carolina,  Inc. (PSNC) in a transaction valued at approximately
$900  million,  including  the  assumption  of debt.  The  transaction  has been
accounted for as a purchase.  PSNC is operated as a  wholly-owned  subsidiary of
SCANA. As a result of the transaction,  SCANA became a registered public utility
holding company under PUHCA.

Georgia Retail Gas Market

         SCANA  Energy,  the retail gas division of Energy  Marketing,  has been
aggressively  marketing  natural gas to residential and commercial  customers in
Georgia.   SCANA  Energy  is  Georgia's   second  largest  gas  marketer,   with
approximately  432,000  customers at December 31, 2000,  or  approximately  a 30
percent market share. For purposes of comparison, SCANA Energy had approximately
431,000  customers at December 31, 1999 and 78,000 at December 31, 1998. In 2000
SCANA Energy  successfully  transitioned from start up to ongoing operations and
for the year ended December 31, 2000  recognized  net earnings of  approximately
$4.4  million.   SCANA  Energy's   strategy   includes  the   determination   of
methodologies to serve all customer classes  profitably and developing  programs
that will enhance  relationships  with those  customers and attract  similar new
customers.  In  addition  SCANA  Energy has  successfully  employed a gas supply
hedging  strategy and has maintained a price structure that is both  competitive
and profitable.  The level of future  revenues and  expenditures is dependent on
several factors, including SCANA Energy's ability to retain customers and market
share,  the  weather,  the margin  achieved on gas sales and its ability to find
industrial interruptible customers to purchase available capacity.

Proposed Interstate Pipeline

         Pipeline  Corporation,  a wholly owned  subsidiary  of the Company,  is
developing  plans for an  interstate  natural gas  pipeline  to ensure  adequate
supplies  to growing gas  markets.  The  anticipated  interstate  pipeline  will
require  Pipeline  Corporation to file an application for approval with the FERC
and other federal and state agencies.

LIQUIDITY AND CAPITAL RESOURCES

        The Company's cash requirements  arise primarily from SCE&G's and PSNC's
operational  needs,  the Company's  construction  program,  the need to fund the
activities or investments of SCANA's  nonregulated  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,  it may be  necessary to seek  increases in rates.  As a
result the Company's future financial position and results of operations will be
affected by the regulated  subsidiaries'  ability to obtain  adequate and timely
rate and other regulatory relief, if requested.

                    The revised estimated primary cash requirements for 2001 and
the actual primary cash requirements for 2000,  excluding  requirements for fuel
liabilities and short-term borrowings, are as follows:

(Millions of Dollars)                               2001          2000
------------------------------------------------------------- --------------

Property additions and construction
   expenditures, net of allowance for
   funds used during construction                   $501          $332
Nuclear fuel expenditures                             26            29
Investments                                           25            20
Maturing obligations, redemptions and
  sinking and purchase fund requirements              14           284
------------------------------------------------------------- --------------
       Total                                        $566          $665
============================================================= ==============

       Approximately  39 percent of total cash  requirements  (after  payment of
dividends) was provided from internal  sources in 2000 as compared to 16 percent
in 1999.

       The Company  anticipates that its 2001 cash  requirements of $566 million
will be met through internally generated funds (approximately 61 percent,  after
payment of dividends), and the incurrence of additional short-term and long-term
indebtedness.  Sales of additional equity securities may also occur. The Company
expects  that it has or can obtain  adequate  sources of  financing  to meet its
projected  cash  requirements  for the next 12  months  and for the  foreseeable
future.

                      SCANA  and PSNC each  have in  effect a  medium-term  note
program  for the  issuance  from  time to time  of  unsecured  medium-term  debt
securities. At December 31, 2000 SCANA had registered with the SEC and available
for issuance $1 billion under this program, the proceeds of which may be used to
refinance  indebtedness  incurred in connection with the acquisition of PSNC, to
fund  additional  business  activities  in  nonutility  subsidiaries,  to reduce
short-term  debt or for general  corporate  purposes.  On February 14, 2001 PSNC
registered $150 million of medium-term notes with the SEC.

                       SCE&G's  First and  Refunding  Mortgage  Bond  Indenture,
dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance
of additional bonds  thereunder  (Class A Bonds) unless net earnings (as therein
defined)  for 12  consecutive  months out of the 18 months prior to the month of
issuance  are at least  twice the annual  interest  requirements  on all Class A
Bonds to be outstanding  (Bond Ratio).  For the year ended December 31, 2000 the
Bond Ratio was 6.43. The Old Mortgage allows the issuance of additional  Class A
Bonds to an additional  principal amount equal to (i) 70 percent of unfunded net
property additions (which unfunded net property additions totaled  approximately
$1,452 million at December 31, 2000),  (ii)  retirements of Class A Bonds (which
retirement  credits totaled $68.4 million at December 31, 2000),  and (iii) cash
on deposit with the Trustee.

       SCE&G is 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 (of which $665 million were  available for such purpose at December 31,
2000).  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, 2000
the New Bond Ratio was 6.34.

       The following  additional  financing  transactions  have  occurred  since
January 1, 2000:

o    On February 8, 2000 the Company  issued $400  million of two-year  floating
     rate notes  maturing  February 8, 2002.  The interest  rate on the notes is
     reset  quarterly  based on  three-month  LIBOR  plus 50 basis  points.  The
     proceeds from these  privately  sold notes were used to consummate  SCANA's
     acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a
     three-year term under a credit  agreement with several banks.  The interest
     rate is reset  every  one,  two,  three or six months and is based on LIBOR
     plus 100 basis  points.  These funds also were used to  consummate  SCANA's
     acquisition of PSNC.

o    On June 14, 2000 SCE&G issued $150 million of First  Mortgage  Bonds having
     an annual  interest rate of 7.50 percent and maturing on June 15, 2005. The
     proceeds  from the sale of these  bonds  were used to pay the  maturity  of
     SCE&G's  $100 million  First  Mortgage  Bonds due June 15, 2000,  to reduce
     short-term debt and for general corporate purposes.

o    On July 13, 2000 SCANA issued $300  million  two-year  floating  rate notes
     maturing on July 15, 2002.  The interest rate is reset  quarterly  based on
     three-month LIBOR plus 65 basis points. Proceeds from the debt were used to
     repay  medium-term  notes totaling $170 million,  to reduce short-term debt
     and for general corporate purposes.

o    On January 24, 2001 SCANA issued $202 million two-year  floating rate notes
     maturing on January 24, 2003. The interest rate is reset quarterly based on
     three-month  LIBOR plus 110 basis points.  Proceeds from the debt were used
     to reduce short-term debt and for general corporate purposes.

o    On January 24, 2001 SCE&G issued $150 million First  Mortgage  Bonds having
     an annual  interest  rate of 6.70 percent and maturing on February 1, 2011.
     The  proceeds  from the sale of these bonds were used to reduce  short-term
     debt and for general corporate purposes.

o    On February 16, 2001 PSNC issued $150 million of  medium-term  notes having
     an annual interest rate of 6.625 percent and maturing on February 15, 2011.
     These funds were used to reduce  short-term debt and for general  corporate
     purposes.

       The Company's electric and natural gas businesses are seasonal in nature,
with the primary  demand for  electricity  being  experienced  during summer and
winter and the primary demand for natural gas being  experienced  during winter.
As a result of the  significant  increase  during the latter half of 2000 in the
cost  to the  Company  of  natural  gas  and  the  colder  than  normal  weather
experienced in December,  the Company experienced  significant  increases in its
working  capital  requirements,  contributing  to the need for the financings by
SCANA and PSNC in early 2001 described above.

       Without the consent of at least a majority of the total  voting  power of
SCE&G's   preferred  stock,   SCE&G  may  not  issue  or  assume  any  unsecured
indebtedness  if, after such issue or assumption,  the total principal amount of
all such  unsecured  indebtedness  would  exceed ten  percent  of the  aggregate
principal amount of all of SCE&G's secured indebtedness and capital and surplus;
however,  no such  consent is required to enter into  agreements  for payment of
principal,  interest and premium for  securities  issued for  pollution  control
purposes.

        Pursuant to Section 204 of the Federal  Power Act,  SCE&G and GENCO must
obtain FERC authority to issue  short-term  debt.  FERC has authorized  SCE&G to
issue up to $250 million of unsecured  promissory notes or commercial paper with
maturity dates of 12 months or less, but not later than December 31, 2002. GENCO
has not sought such authorization.

       At December 31, 2000 SCE&G had $250 million of unused authorized lines of
credit  which  consist of a credit  agreement  for a maximum of $250  million to
support the issuance of commercial paper SCE&G's commercial paper outstanding at
December 31, 2000 and 1999 was $117.5 million and $143.1 million,  respectively.
In addition,  Fuel Company has a credit  agreement for a maximum of $125 million
with the full  amount  available  at December  31,  2000.  The credit  agreement
supports  the  issuance of  short-term  commercial  paper for the  financing  of
nuclear and fossil fuels and sulfur dioxide  emission  allowances.  Fuel Company
commercial  paper  outstanding  at  December  31, 2000 was $70.2  million.  This
commercial paper and amounts  outstanding  under the revolving credit agreement,
if any, are guaranteed by SCE&G.

       At December  31, 2000 PSNC had $125  million  authorized  lines of credit
which consist of a credit agreement for a maximum of $125 million to support the
issuance  of  commercial  paper.  Unused  lines of credit at  December  31, 2000
totaled $125 million.  PSNC's  commercial paper outstanding on December 31, 2000
was $125 million.

       SCE&G's  Restated   Articles  of  Incorporation   prohibit   issuance  of
additional   shares  of  preferred   stock  without  consent  of  the  preferred
stockholders  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  (Preferred Stock Ratio).  For the year ended December 31, 2000 the
Preferred Stock Ratio was 2.09.

         As a result of SCANA's  acquisition of PSNC on February 10, 2000,  PSNC
shareholders  were paid $212  million in cash and 17.4  million  shares of SCANA
common stock valued at  approximately  $488  million.  In  connection  with this
transaction,  certain SCANA shareholders were paid $488 million in cash for 16.3
million shares of SCANA common stock. During 2000, shares for the Stock Purchase
Savings Plan and the Investor Plus Plan were purchased on the open market.

         On  September  21,  1999 SCE&G  announced  a $256  million  gas turbine
generator project in Aiken County, South Carolina.  Two combined-cycle  turbines
will burn natural gas to produce 300  megawatts of new electric  generation  and
use  exhaust  heat to replace  coal-fired  steam that  powers  two  existing  75
megawatt  turbines at the Urquhart  Generating  Station.  The turbine project is
scheduled to be completed by June 2002.

         On October 15, 1999 FERC notified  SCE&G of its agreement  with SCE&G's
plan to  reinforce  Lake Murray Dam in order to maintain  the lake in case of an
extreme earthquake.  SCE&G and FERC have been discussing possible  reinforcement
alternatives  for the dam over the past several years as part of SCE&G's ongoing
hydroelectric operating license with FERC. Until discussions are concluded it is
not possible to finalize the cost of the project;  however,  it is possible that
the costs could range up to $250 million.  Although any costs  incurred by SCE&G
are expected to be recoverable  through electric rates,  SCE&G also is exploring
alternative sources of funding. The project is expected to be completed in 2004.

         On October 7, 2000  Summer  Station  was  removed  from  service  for a
planned  maintenance and refueling outage scheduled to last 38 1/2 days.  During
initial inspection  activities,  plant personnel  discovered a small leak coming
from  a hole  in a weld  in a  primary  coolant  system  pipe.  SCE&G  performed
extensive  ultrasonic  testing of similar  welds in the  cooling  system,  which
confirmed  that the  problem  was  limited  to this  single  weld.  A root cause
analysis  determined  that the  cause of the  crack  was  primary  water  stress
corrosion cracking.  The repair involved cutting out a twelve-inch long spool of
the pipe,  which  included  the entire weld,  and  installing a new spool piece.
Repairs  have  been  completed  and the  integrity  of the new  welds  have been
verified through extensive  testing.  The plant was returned to service in March
2001. The NRC was closely involved  throughout this process and approved SCE&G's
actions  to repair  the  crack,  as well as the  restart  schedule.  SCE&G  will
continue  to monitor  primary  coolant  system  pipes  during  the next  outage,
scheduled for Spring of 2002. SCE&G recorded a pretax charge of approximately $6
million  in the  fourth  quarter  of 2000  to  expense  repair  costs  to  date.
Additional  costs  that may be  recorded  in the first  quarter  of 2001 are not
expected  to be  material.  The  cost of  replacement  power is  expected  to be
recovered through SCE&G's electric fuel adjustment clause.

        In January 2001 SCE&G's 385 megawatt  coal-fired Cope Generating Station
was taken out of service due to an electrical ground in the generator.  The unit
is expected to be returned to service in Spring  2001.  The cost of  replacement
power is expected to be recovered through SCE&G's fuel adjustment clause.

        SCANA and  Westvaco  each own a 50 percent  interest  in Cogen South LLC
(Cogen).  Cogen was  formed to build and  operate  a  cogeneration  facility  at
Westvaco's Kraft Division Paper Mill in North  Charleston,  South Carolina.  The
facility began operations in March 1999. On September 10, 1998 the contractor in
charge of  construction  filed suit in Circuit Court seeking  approximately  $52
million  from  Cogen,  alleging  that it  incurred  construction  cost  overruns
relating  to the  facility  and  that the  construction  contract  provides  for
recovery of these costs.  In addition to Cogen,  Westvaco,  SCE&G and SCANA were
also named as defendants in the suit. SCANA and the other defendants believe the
suit is without merit and are mounting an  appropriate  defense.  SCANA does not
believe  that the  resolution  of this issue will have a material  impact on its
results of operations, cash flows or financial position.

Environmental Matters

         The Clean Air Act (CAA) required electric utilities to reduce emissions
of sulfur  dioxide and  nitrogen  oxide  substantially  by the year 2000.  These
requirements  were phased in over two periods.  The first phase had a compliance
date of  January  1,  1995  and the  second,  January  1,  2000.  The  Company's
facilities did not require  modifications  to meet the  requirements of Phase I.
The Company is meeting the Phase II requirements  through the burning of natural
gas and/or lower sulfur coal in its generating units and the purchase and use of
sulfur  dioxide  emission  allowances.  Low  nitrogen  oxide  burners  have been
installed to reduce nitrogen oxide emissions to the levels required by Phase II.
The EPA has indicated that it will propose  regulations  for stricter  limits on
mercury and other toxic  pollutants  generated by coal-fired  plants by December
2003 and will begin developing these regulations shortly.

         SCE&G and GENCO filed  compliance  plans with DHEC  related to Phase II
sulfur  dioxide  requirements  in 1995 and  Phase II oxides  of  nitrogen  (NOx)
requirements in 2000, 1999, 1998 and 1997. The Company currently  estimates that
air  emissions  control  equipment  will require  capital  expenditures  of $141
million  over  the  2001-2005  period  to  retrofit  existing  facilities,  with
increased  operation and maintenance costs of approximately $3 million per year.
To meet  compliance  requirements  for the years 2006 through 2010,  the Company
anticipates additional capital expenditures of approximately $5 million.

         In  October  1998 the EPA  issued a final  rule  requiring  22  states,
including South Carolina,  to modify their state  implementation  plans (SIP) to
address  the issue of NOx  pollution.  On May 25, 1999 a federal  appeals  court
delayed  indefinitely the implementation of the rule. On March 3, 2000 the court
affirmed  the  EPA's  NOx rule  for the  affected  states.  South  Carolina  was
subsequently  ordered to amend its SIP to achieve  significant  NOx  reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and the
EPA has issued  official notice to South Carolina (and a number of other states)
to comply.  While not final,  South  Carolina has proposed NOx  reductions  that
would require the Company to install pollution control  equipment.  Because DHEC
had not amended its SIP as of December  31, 2000 to set out or allocate  any NOx
reductions,  it is not possible to estimate what, if any,  capital  expenditures
will be required to comply with any potential mandated reductions.

         The EPA has undertaken an aggressive enforcement initiative against the
industry and the  Department  of Justice (DOJ) has brought suit against a number
of utilities  in federal  court  alleging  violations  of the CAA.  Prior to the
suits,  those utilities had received  requests for information under Section 114
of the CAA, and were issued Notices of Violation  prior to the suits.  The basis
for these suits is the claim by the EPA that maintenance  activities  undertaken
by the utilities over the past 20 or more years constitute "major modifications"
which would have  required the  installation  of costly Best  Available  Control
Technology  (BACT). The Company and SCE&G have received and responded to Section
114 requests for information related to Canadys,  Wateree and Williams Stations.
Similar requests have been sent to a number of other utilities  nationwide.  The
regulations under the CAA provide certain exemptions to the definition of "major
modifications,"  particularly  an exemption for routine  repair,  replacement or
maintenance.  The Company has  analyzed  each of the  activities  covered by the
EPA's requests and believes each activity  represents prudent practice regularly
performed   throughout  the  utility  industry  as  necessary  to  maintain  the
operational  efficiency and safety of equipment.  As such, the Company  believes
that each of these  activities is covered by the  exemption for routine  repair,
replacement  and  maintenance  and that the EPA is changing,  or  attempting  to
change through enforcement  actions,  the intent and meaning of its regulations.
The Company also believes that,  even if some of the activities in question were
found not to qualify for the routine  exemption,  there were no increases either
in annual emissions or in the maximum hourly emissions  achievable at any of the
units caused by any of the activities.  The regulations provide an exemption for
increased  hours of operation or production  rate and for increases in emissions
resulting  from  demand  growth.  It is  possible  that the EPA will  eventually
commence enforcement actions against SCE&G relative to those plants. The EPA has
the authority to seek  penalties  for the alleged  violations in question at the
rate of up to  $27,500  per day for  each  violation.  The EPA also  would  seek
installation  of BACT (or  equivalent)  at the three plants as well. The Company
believes  that the  EPA's and  DOJ's  claims  are  without  merit,  and that any
enforcement  action,  up to and including a lawsuit  resulting  from this issue,
will not have a material adverse effect on the Company's  financial  position or
results of operations.

         The Federal Clean Water Act, as amended, provides for the imposition of
effluent  limitations  that require  various  levels of treatment for each waste
water  discharge.  Under this Act,  compliance  with  applicable  limitations is
achieved under a national permit program. Discharge permits have been issued for
all and  renewed  for  nearly  all of  SCE&G's  and  GENCO's  generating  units.
Concurrent with renewal of these permits,  the permitting agency has implemented
a more rigorous  program in monitoring and  controlling  thermal  discharges and
strategies for toxicity  reduction in wastewater  streams.  The Company has been
developing compliance plans for these initiatives. Amendments to the Clean Water
Act proposed in Congress  include several  provisions  which,  if passed,  could
prove  costly  to SCE&G  and  GENCO.  These  include,  but are not  limited  to,
limitations  to  mixing  zones  and  the   implementation  of   technology-based
standards. In December 2000 SCE&G entered into a Consent Order with DHEC related
to a malfunction of the waste water treatment facility at Hagood Station.
The order requires SCE&G to correct the violation.

         The Company maintains an environmental  assessment  program to identify
and assess current and former operations sites that could require  environmental
cleanup. As site assessments are initiated,  estimates are made of the amount of
expenditures,  if any,  deemed  necessary to investigate and clean up each site.
These  estimates  are  refined  as  additional  information  becomes  available;
therefore,  actual  expenditures  could differ  significantly  from the original
estimates.  Amounts  estimated  and  accrued  to date for site  assessments  and
cleanup relate primarily to regulated operations.  Such amounts are deferred and
amortized with recovery provided through rates.

         SCE&G has also  recovered  portions  of its  environmental  liabilities
through  settlements  with various  insurance  carriers,  including  all amounts
previously  deferred for its electric  operations.  SCE&G expects to recover all
deferred  amounts  related to its gas  operations  by  December  2005.  Deferred
amounts,  net of amounts  recovered  through  rates and  insurance  settlements,
totaled  $20.2  million  and  $23.7  million  at  December  31,  2000 and  1999,
respectively.  The deferral  includes the estimated  costs  associated  with the
following matters.

     o    In September 1992 the EPA notified  SCE&G,  the City of Charleston and
          the Charleston Housing Authority of their potential  liability for the
          investigation and cleanup of the Calhoun Park area site in Charleston,
          South  Carolina.  This  site  encompasses  approximately  30 acres and
          includes  properties  which were locations for industrial  operations,
          including  a  wood  preserving   (creosote)   plant,  one  of  SCE&G's
          decommissioned MGPs, properties owned by the National Park Service and
          the City of Charleston and private  properties.  The site has not been
          placed  on the  National  Priorities  List,  but may be  added  in the
          future. The PRPs negotiated an administrative order by consent for the
          conduct   of  a   Remedial   Investigation/Feasibility   Study  and  a
          corresponding  Scope of Work.  Field work began in November  1993, and
          the EPA approved a Remedial  Investigation Report in February 1997 and
          a Feasibility Study Report in June 1998. In July 1998 the EPA approved
          SCE&G's Removal Action Work Plan for soil excavation.  SCE&G completed
          Phase  One of the  Removal  Action  Work  Plan  in  1998  at a cost of
          approximately  $1.5 million.  Phase Two, which cost approximately $3.5
          million,  included  excavation and  installation of several  permanent
          barriers to mitigate coal tar seepage.  On September 30, 1998 a Record
          of Decision  was issued  which sets forth the EPA's view of the extent
          of each PRP's  responsibility  for site contamination and the level to
          which the site must be remediated.  SCE&G estimates that the Record of
          Decision will result in costs of approximately $13.3 million, of which
          approximately $2 million remains. On January 13, 1999 the EPA issued a
          Unilateral  Administrative  Order for  Remedial  Design  and  Remedial
          Action  directing  SCE&G to design and carry out a plan of remediation
          for the Calhoun Park site.  SCE&G submitted a  Comprehensive  Remedial
          Design  Work Plan  (RDWP) on  December  17,  1999 and  proceeded  with
          implementation  pending agency approval.  The RDWP was approved by the
          EPA in July 2000, and its implementation continues.

          In  October  1996  the  City  of  Charleston  and  SCE&G  settled  all
          environmental claims the City may have had against SCE&G involving the
          Calhoun  Park  area for a  payment  of $26  million  over  four  years
          (1996-1999)  by SCE&G to the City.  SCE&G is recovering  the amount of
          the  settlement,  which does not encompass site assessment and cleanup
          costs,  through rates in the same manner as other amounts  accrued for
          site  assessments  and  cleanup  as  discussed  above.  As part of the
          environmental  settlement,  SCE&G  constructed  an 1,100 space parking
          garage on the Calhoun Park site  (construction  was completed in April
          2000) and transferred the facility to the City in exchange for a $16.5
          million,  18-year  municipal bond collaterized by revenues from, and a
          mortgage on, the parking garage.

     o    SCE&G owns three other decommissioned MGP sites which contain residues
          of  by-product  chemicals.  For the  site  located  in  Sumter,  South
          Carolina,  effective September 15, 1998, SCE&G entered into a Remedial
          Action  Plan  Contract  with  DHEC  pursuant  to  which it  agreed  to
          undertake  a  full  site   investigation  and  remediation  under  the
          oversight  of  DHEC.  Site  investigation  and   characterization  are
          proceeding  according  to  schedule.  Upon  selection  and  successful
          implementation of a site remedy, DHEC will give SCE&G a Certificate of
          Completion,  and a  covenant  not to sue.  For  the  site  located  in
          Florence, South Carolina, SCE&G entered into a similar Remedial Action
          Plan  Contract  with  DHEC  effective  September  5,  2000.  SCE&G  is
          continuing  to  investigate  the  remaining  site in Columbia,  and is
          monitoring the nature and extent of residual contamination.

 In addition,  PSNC owns, or has owned,  all or portions of seven sites in North
Carolina  on  which  MGPs  were  formerly  operated.   Intrusive   investigation
(including drilling,  sampling and analysis) has begun at only one site, and the
remaining sites have been evaluated using historical records and observations of
current site conditions . These evaluations have revealed that MGP residuals are
present or suspected at several of the sites.  The North Carolina  Department of
Environment  and Natural  Resources has  recommended  that no further  action be
taken with respect to one site. An  environmental  due diligence  review of PSNC
conducted in February  1999  estimated  that the cost to remediate the remaining
sites would range  between  $11.3  million to $21.9  million.  During the second
quarter of 2000,  the review  was  finalized  and the  estimated  liability  was
recorded.  PSNC is unable to  determine  the rate at which costs may be incurred
over this time  period.  The  estimated  cost range has not been  discounted  to
present value.  PSNC's  associated actual costs for these sites will depend on a
number of  factors,  such as actual  site  conditions,  third-party  claims  and
recoveries  from other PRPs. An order of the NCUC dated May 11, 1993  authorized
deferral  accounting  for  all  costs  associated  with  the  investigation  and
remediation of MGP sites. At December 31, 2000 PSNC has recorded a liability and
associated regulatory asset of $10.2 million,  which reflects the minimum amount
of the range,  net of shared cost recovery from other PRPs.  Amounts incurred to
date are not material.  Management intends to request recovery of additional MGP
cleanup  costs not recovered  from other PRPs in future rate case  filings,  and
believes that all costs incurred will be recoverable in gas rates.

Regulatory Matters

         South Carolina Electric & Gas Company

        On July 20, 2000 the PSC issued an order  approving  SCE&G's request for
an  out-of-period  adjustment to increase the cost of gas component of its rates
for natural gas service  from 54.334  cents per therm to 68.835 cents per therm,
effective  with the first billing cycle in August 2000. As part of its regularly
scheduled  annual  review of gas costs,  the PSC issued an order on  November 9,
2000 which  further  increased  the cost of gas  component  to 78.151  cents per
therm,  effective with the first billing cycle in November 2000. On December 21,
2000 the PSC issued an order approving SCE&G's request for another out-of-period
adjustment  to increase  the cost of gas  component  to 99.340  cents per therm,
effective  with the first  billing  cycle in January 2001. In March 2001 the PSC
approved  SCE&G's  request to decrease the cost of gas component to 79.340 cents
per therm, effective with the first billing cycle in March 2001.

        On July 5, 2000 the PSC  approved  SCE&G's  request to  implement  lower
depreciation  rates  for  its  gas  operations.  The new  rates  were  effective
retroactively  to  January  1,  2000 and will  result in a  reduction  in annual
depreciation expense of approximately $2.9 million.

        On September 14, 1999 the PSC approved an accelerated  capital  recovery
plan for SCE&G's Cope Generating  Station.  The plan was  implemented  beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery  methodology  wherein  SCE&G  may  increase  depreciation  of its  Cope
Generating  Station  in excess of  amounts  that  would be  recorded  based upon
currently   approved   depreciation   rates.   The  amount  of  the  accelerated
depreciation  will be  determined  by SCE&G based on the level of  revenues  and
operating  expenses,  not to exceed $36 million annually without the approval of
the PSC. Any unused  portion of the $36 million in any given year may be carried
forward for  possible  use in the  following  year.  As of December  31, 2000 no
accelerated  depreciation  has been recorded.  The accelerated  capital recovery
plan will be accomplished through existing customer rates.

        On December 11, 1998 the PSC issued an order  requiring  SCE&G to reduce
retail electric rates on a prospective basis. The PSC acted in response to SCE&G
reporting  that it earned a 13.04 percent return on common equity for its retail
electric  operations for the 12 months ended  September 30, 1998. This return on
common  equity  exceeded  SCE&G's  authorized  return  of 12.0  percent  by 1.04
percent,  or $22.7  million,  primarily  as a result of record heat  experienced
during the summer.  The order  required  prospective  rate  reductions  on a per
kilowatt-hour  basis,  based on actual  retail  sales  for the 12  months  ended
September  30,  1998.  On January  12,  1999 the PSC denied  SCE&G's  motion for
reconsideration,  ruled that no further rate action was required, and reaffirmed
SCE&G's  authorized  return on equity of 12.0 percent.  The rate reductions were
placed into effect with the first billing cycle of January 1999.

        On January 9, 1996 the PSC issued an order granting SCE&G an increase in
retail  electric  rates which were fully  implemented  by January 1997.  The PSC
authorized  a return on common  equity of 12.0  percent.  The PSC also  approved
establishment  of a Storm  Damage  Reserve  Account  capped at $50 million to be
collected through rates over a ten-year period.  Additionally,  the PSC approved
accelerated  recovery of a significant  portion of SCE&G's  electric  regulatory
assets  (excluding  deferred  income tax  assets) and the  remaining  transition
obligation  for  postretirement  benefits  other  than  pensions,  changing  the
amortization  periods to allow  recovery  by the end of the year  2000.  SCE&G's
request  to shift,  for  rate-making  purposes,  approximately  $257  million of
depreciation  reserves  from  transmission  and  distribution  assets to nuclear
production  assets  was also  approved.  The  Consumer  Advocate  and two  other
intervenors appealed certain issues in the order initially to the Circuit Court,
which affirmed the PSC's decisions,  and subsequently,  to the Supreme Court. In
March  1998,  SCE&G,  the  PSC,  the  Consumer  Advocate  and  one of the  other
intervenors  reached an agreement that provided for the reversal of the shift in
depreciation  reserves and the dismissal of the appeal of all other issues.  The
PSC also authorized SCE&G to adjust depreciation rates that had been approved in
the 1996 rate order for its  electric  transmission,  distribution  and  nuclear
production  properties to eliminate the effect of the depreciation reserve shift
and to  retroactively  apply such  depreciation  rates to  February  1996.  As a
result,  a  one-time  reduction  in  depreciation  expense of $9.8  million  was
recorded in March 1998. The agreement does not affect retail electric rates. The
FERC had  previously  rejected the transfer of  depreciation  reserves for rates
subject to its  jurisdiction.  In September  1998 the Supreme Court affirmed the
Circuit Court's rulings on the issues contested by the remaining intervenor.

        In 1994 the PSC  issued an order  approving  SCE&G's  request to recover
through a billing  surcharge  to its gas  customers  the costs of  environmental
cleanup at the sites of former MGPs. The billing  surcharge is subject to annual
review and provides for the recovery of  substantially  all actual and projected
site  assessment  and cleanup costs and  environmental  claims  settlements  for
SCE&G's gas operations that had previously been deferred. In November 2000, as a
result of the annual review,  the PSC approved  SCE&G's  request to maintain the
billing  surcharge  at  $.011  per  therm to  provide  for the  recovery  of the
remaining balance of $20.1 million.

        In September 1992 the PSC issued an order granting SCE&G's request for a
$.25  increase in transit fares from $.50 to $.75 in Columbia,  South  Carolina;
however,  the PSC also required  $.40 fares for low income  customers and denied
SCE&G's request to reduce the number of routes and frequency of service. The new
rates were placed into effect in October 1992. SCE&G appealed the PSC's order to
the  Circuit  Court,  which in May  1995  ordered  the case  back to the PSC for
reconsideration  of  several  issues  including  the low income  rider  program,
routing  changes,  and the $.75 fare.  The Supreme  Court  declined to review an
appeal of the Circuit Court  decision and dismissed the case.  The PSC and other
intervenors filed another Petition for Reconsideration,  which the Supreme Court
denied.  The PSC and other intervenors filed another appeal to the Circuit Court
which the Circuit Court denied in an order dated May 9, 1996. In this order, the
Circuit Court upheld its previous  orders and remanded  them to the PSC.  During
August  1996 the PSC heard  oral  arguments  on the  orders  on remand  from the
Circuit  Court.  On  September  30, 1996 the PSC issued an order  affirming  its
previous orders and denied SCE&G's request for  reconsideration.  In response to
an appeal of the PSC's order by SCE&G,  the Circuit Court issued an order on May
25, 2000,  which  remanded the matter to the PSC for review of SCE&G's  original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC  issued  an order  granting  the  relief  requested  by  SCE&G.  On
September 29, 2000 the Consumer  Advocate filed a motion with the PSC for a stay
of this  order to which  SCE&G  filed a  response.  On  October  3, 2000 the PSC
accepted  the  Consumer  Advocate's  motion and issued a stay of its order.  The
Consumer  Advocate and other  intervenors  have petitioned the Circuit Court for
judicial review of the PSC's order granting relief.  Action by the Circuit Court
is pending.

       Public Service Company of North Carolina, Incorporated

         A state  expansion  fund,  established  by the North  Carolina  General
Assembly  in  1991  and  funded  by  refunds  from  PSNC's  interstate  pipeline
transporters,  provides  financing for expansion into areas that otherwise would
not be  economically  feasible  to serve.  On  December  30,  1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison,  Jackson and
Swain Counties,  North Carolina.  Pursuant to state statutes,  the NCUC required
PSNC to forfeit its exclusive  franchises to serve six counties in western North
Carolina  effective  January 31, 2000 because these  counties were not receiving
any natural gas service.  Madison,  Jackson and Swain  Counties were included in
the forfeiture  order.  On June 29, 2000 the NCUC approved  PSNC's  requests for
reinstatement  of its  exclusive  franchises  for  Madison,  Jackson  and  Swain
Counties and  disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million.

         On December 7, 1999 the NCUC issued an order  approving the acquisition
of PSNC by the Company.  As specified in the NCUC order,  PSNC reduced its rates
by approximately $1 million in August 2000, will reduce rates another $1 million
in August 2001 and has agreed to a five-year  moratorium  on general rate cases.
General  rate  relief  can be  obtained  during  this  period to  recover  costs
associated  with  materially  adverse  governmental  actions  and force  majeure
events.

        On  February  22,  1999  the NCUC  approved  PSNC's  application  to use
expansion  funds to  extend  natural  gas  service  into  Alexander  County  and
authorized  disbursements from the fund of approximately $4.3 million based upon
budgeted  construction  cost of  approximately  $6.2 million.  Most of Alexander
County lies within PSNC's certificated  service territory and did not previously
have  natural gas  service.  The  project  was  completed  and  customers  began
receiving natural gas service in March 2000.

        On October 30, 1998 the NCUC issued an order in PSNC's general rate case
filed in April  1998.  The  order,  effective  November  1, 1998,  granted  PSNC
additional  revenue of $12.4 million and allowed a 9.82 percent  overall rate of
return on PSNC's net utility  investment.  It also approved the  continuation of
the Weather  Normalization  Adjustment  and Rider D  Mechanisms  and full margin
transportation  rates. PSNC's Rider D rate 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.  On February 4, 2000,  in
response to an appeal by CUCA, the Supreme Court of North Carolina  affirmed the
NCUC order.

        On November 6, 1997 the NCUC issued an order permitting PSNC, on a trial
basis,  to  establish  its  commodity  cost  of gas  for  large  commercial  and
industrial  customers  on the basis of market  prices for  natural  gas.  PSNC's
request for permanent approval of this mechanism was approved by the NCUC via an
order issued April 6, 2000.

        The Company's  regulated  business  operations were impacted by the NEPA
and FERC  Orders  No.  636,  888 and 2000.  NEPA was  designed  to create a more
competitive   wholesale  power  supply  market  by  creating  "exempt  wholesale
generators"  and  by  potentially   requiring   utilities  owning   transmission
facilities  to provide  transmission  access to  wholesalers.  Order No. 636 was
intended  to  deregulate  the  markets  for  interstate  sales of natural gas by
requiring  that  pipelines  provide  transportation  services  that are equal in
quality  for all gas  suppliers  whether  the  customer  purchases  gas from the
pipeline or another  supplier.  Orders No. 888 and 2000 require  utilities under
FERC  jurisdiction  that own,  control  or  operate  transmission  lines to file
nondiscriminatory open access tariffs that offer to others the same transmission
service  they  provide  to  themselves  and to  submit  plans  for the  possible
formulation of an RTO. In the opinion of the Company, it continues to be able to
meet successfully the challenges of these altered business climates and does not
anticipate any material adverse impact on the results of operations, cash flows,
financial position or business prospects.

Other

        At December 31, 2000 SCANA Communications Holdings, Inc. (SCH), a wholly
owned,  indirect  subsidiary  of SCANA,  held the following  investments  in ITC
Holding Company, Inc. (ITC) and its affiliates:

     o    Powertel,  Inc.  (Powertel) is a publicly traded company that owns and
          operates  personal  communications  services  (PCS) systems in several
          major Southeastern  markets. SCH owns approximately 4.9 million common
          shares of Powertel at a cost of approximately $77.7 million.  Powertel
          common  stock  closed at  $61.9375  per share on  December  31,  2000,
          resulting in a pre-tax  unrealized  holding gain of $228.8  million (a
          decline of $189.0 million from December 31, 1999).  Accumulated  other
          comprehensive  income includes the after-tax  amount of all unrealized
          holding gains and losses on common shares.  In addition,  SCH owns the
          following series of non-voting  convertible  preferred  shares, at the
          approximate  cost  noted:  100,000  shares  series B ($75.1  million);
          50,000 shares series D ($22.5 million);  and 50,000 shares 6.5 percent
          series E ($75.0 million).  Cumulative  dividends on preferred series E
          shares are generally paid in common shares of Powertel and are accrued
          quarterly.  Preferred series B shares become convertible in March 2002
          at a conversion price of $16.50 per common share or approximately  4.6
          million common shares. Preferred series D shares become convertible in
          March  2002 at a  conversion  price  of  $12.75  per  common  share or
          approximately  1.7 million  common shares.  Preferred  series E shares
          become  convertible  in June 2003 at a conversion  price of $22.01 per
          common share or  approximately  3.4 million common shares.  The market
          value of the convertible  preferred  shares of Powertel is not readily
          determinable.   However,  as  converted,   the  market  value  of  the
          underlying  common shares for the preferred  shares was  approximately
          $606.9 million at December 31, 2000,  reflecting an unrecorded pre-tax
          holding  gain of $434.3  million  (a decline  of $368.4  million  from
          December 31, 1999).

        OnAugust 28, 2000 SCH announced that under terms of separate  definitive
          agreements,  Powertel  has agreed to be  acquired  by either  Deutsche
          Telekom  AG or  VoiceStream  Wireless  Corporation  (VoiceStream).  If
          Deutsche Telekom's previously announced  acquisition of VoiceStream is
          successfully  completed,  then  Deutsche  Telekom  would also  acquire
          Powertel.  If the Deutsche  Telekom - VoiceStream  transaction  is not
          completed, then VoiceStream would acquire Powertel. In connection with
          these transactions,  SCH entered into stockholder agreements with each
          of Deutsche  Telekom and  VoiceStream  pursuant to which SCH agreed to
          vote its Powertel  shares in support of either of these  transactions.
          In addition,  SCH agreed to certain restrictions on disposition of its
          Powertel  shares  and the  shares it would  receive in either of these
          transactions.  On March 13, 2001  Powertel  shareholders  approved the
          acquisition agreements.

     o    ITC^DeltaCom,   Inc.  (ITCD)  is  a  fiber  optic   telecommunications
          provider.  SCH owns approximately 5.1 million common shares of ITCD at
          a cost of  approximately  $43.0  million.  ITCD common stock closed at
          $5.39  per  share  on  December  31,  2000,  resulting  in  a  pre-tax
          unrealized  holding loss of $15.4 million (a decline of $113.7 million
          from  December  31,  1999).  Accumulated  other  comprehensive  income
          includes the  after-tax  amount of all  unrealized  holding  gains and
          losses on common shares.  In addition,  SCH owns  1,480,771  shares of
          series  A  preferred  stock of ITCD at a cost of  approximately  $11.2
          million.  Series A preferred  shares become  convertible in March 2002
          into 2,961,542 shares of ITCD common stock. The market value of series
          A preferred  stock of ITCD is not readily  determinable.  However,  as
          converted,  the market  value of the  underlying  common stock for the
          series A preferred stock was  approximately  $16.0 million at December
          31,  2000,  reflecting  an  unrecorded  pre-tax  holding  gain of $4.8
          million (a decline of $65.8 million from December 31, 1999).

     o    Knology,  Inc.  (Knology)  is a broad-band  service  provider of cable
          television, telephone and internet services. SCH owns $71,050,000 face
          amount of 11.875  percent  Senior  Discount  Notes due 2007 of Knology
          Broadband,  Inc., a  wholly-owned  subsidiary  of Knology.  The Senior
          Discount Notes have a book basis at December 31, 2000 of approximately
          $57.9 million. In addition,  SCH owns approximately 7.2 million shares
          of Knology Series A Convertible  Preferred  Stock with a cost basis of
          approximately $5.0 million and warrants to purchase  approximately 0.2
          million shares of Series A Convertible Preferred Stock. On January 12,
          2001 SCH invested $25.0 million for  approximately  8.3 million shares
          of Series C Convertible  Preferred Stock of Knology.  The market value
          of these investments is not readily determinable.

     o    ITC holds ownership interests in several  Southeastern  communications
          companies, including those discussed above. SCH owns approximately 3.1
          million common shares,  645,153 series A convertible preferred shares,
          and  133,664  series B  convertible  preferred  shares  of ITC.  These
          investments cost  approximately $5.8 million,  $7.2 million,  and $4.0
          million,  respectively. The market values of these investments are not
          readily determinable.

        In June 1998 the  Financial  Accounting  Standards  Board (FASB)  issued
Statement  of  Financial   Accounting  Standards  (SFAS)  133,  "Accounting  for
Derivative  Instruments  and Hedging  Activities." In June 2000, the FASB issued
SFAS 138,  which  amends  certain  provisions  of SFAS 133 to expand  the normal
purchase and sale exemption for supply  contracts and to redefine  interest rate
risk to reduce  sources of  ineffectiveness,  among  other  things.  The Company
utilizes various derivatives in its risk management activities,  including swaps
and commodities futures. The Company adopted SFAS 133, as amended, on January 1,
2001.  As a result  of  adopting  SFAS 133,  the  Company  recorded  a credit of
approximately $23.0 million, net of tax, as the effect of a change in accounting
principle  (transition  adjustment) to other comprehensive  income on January 1,
2001. This amount represents the  reclassification of unrealized gains that were
deferred and reported as  liabilities  at December 31, 2000. In the future,  all
gains/losses   related  to  qualifying   cash  flow  hedges  deferred  in  other
comprehensive  income  will be  reclassified  to earnings at the time the hedged
transaction affects earnings.

       In December 1999 Staff Accounting Bulletin No. 101, "Revenue  Recognition
in  Financial  Statements"  was issued by the SEC,  and provides the SEC staff's
views in applying generally accepted  accounting  principles to selected revenue
recognition  issues.  The  Company's  adoption  of this  bulletin  in the fourth
quarter  of 2000 had no impact  on its  results  of  operations,  cash  flows or
financial position.

     ServiceCare,  Inc. has announced  the sale of its home  security  business,
expected to be completed in March 2001. SCANA Communications,  Inc. has signed a
letter  of  intent to sell its 800 Mhz radio  service  network,  expected  to be
completed in April 2001.

RESULTS OF OPERATIONS

Earnings and Dividends

     Earnings per share of common stock and the rate of return  earned on common
equity for 2000, 1999 and 1998 were as follows:

                                                  2000       1999      1998
    --------------------------------------------------------------------------
    --------------------------------------------------------------------------
    Earnings derived from:
        Continuing operations                     $2.12     $1.39    $2.07
        Non-recurring gains                           -       .34      .05
        Cumulative effect of accounting change,
         net of taxes                               .28        -        -
    --------------------------------------------------------------------------
        Earnings per weighted average share       $2.40     $1.73    $2.12
    ==========================================================================

    Return earned on common equity                 12.3%      8.5%    12.8%
    --------------------------------------------------------------------------

o     2000 vs 1999    Earnings derived from continuing operations increased
                      $0.73, primarily as a result of improved
                      results from  retail gas marketing ($.04 net earnings for
                      2000 compared to $.45 loss in 1999) and
                      the acquisition of PSNC ($.21).  In addition, electric
                      margin improved $.36 (see discussion at
                      Electric Operations), regulated gas margin (excluding
                      PSNC) improved $.07 and pension income
                      increased $.05.  These improvements were partially offset
                      by increased interest expense of $.36,  a
                      charge for repairs at Summer Station ($.04) and other
                      increases in operations and maintenance ($.05).

o     1999 vs 1998    Earnings derived from continuing operations decreased
                      $.68, primarily as a result of losses from the
                      Company's entry into the Georgia retail gas market ($.37
                      greater loss in 1999).  In addition,
                      electric margin decreased $.12 (see discussion at Electric
                      Operations), gas margin decreased $.04,
                      and expenses were higher for other operations and
                      maintenance ($.04), depreciation and amortization
                      ($.09) and interest expense ($.11).  These decreases were
                      partially offset by improved results from
                      energy marketing activities ($.03), the impact of fewer
                      common shares outstanding ($.03), and other ($.03).

         Pension income  recorded by the Company reduced  operations  expense by
$22.7 million,  $17.3 million and $16.9 million for the years ended December 31,
2000, 1999 and 1998,  respectively.  In addition  pension income increased other
income by $12.8  million,  $10.5  million  and $9.0  million for the years ended
December 31, 2000,  1999 and 1998,  respectively.  The  reductions to operations
expense for 1999 and 1998 were substantially offset by accelerated  amortization
of a  significant  portion  of  the  transition  obligation  for  postretirement
benefits  other than pensions and certain  regulatory  assets as approved by the
PSC.  Effective July 1, 2000 the Company's pension plan was amended to provide a
cash  balance  formula.  The  effect of this plan  amendment  was to reduce  net
periodic  benefit income for the year ended  December 31, 2000 by  approximately
$3.7 million.

         Non-recurring  gains  resulted from the sale of retail  propane  assets
($.29) and telecommunications  towers ($.05) in 1999 and a retroactive change in
electric  depreciation rates ($.05) in 1998. In 2000 the cumulative effect of an
accounting  change  resulted from the recording of unbilled  revenues by SCANA's
retail  utility  subsidiaries  (see  Note 2 of Notes To  Consolidated  Financial
Statements).

         Return on common  equity  increased in 2000  primarily due to increased
earnings and decreased  common equity due to a $197 million  unrealized  loss on
the  Company's  investment  in  telecommunications  securities  during the year.
Increased  earnings  related  to the  cumulative  effect  of  accounting  change
increased the return on common  equity by 1.4 percent in 2000. In addition,  the
$197 million unrealized loss on the Company's  investments in telecommunications
securities  increased the return on common equity by 1.1 percent in 2000. Return
on common equity decreased in 1999 due to decreased  earnings and a $311 million
unrealized gain on the Company's investments in  telecommunications  securities.
The increase in common equity,  without a  proportional  increase in net income,
decreased the return earned on common equity by 1.6 percent in 1999.

         The  Company's  financial  statements  include  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  2.3 percent of
income before income taxes in 2000, 2.4 percent in 1999 and 4.4 percent in 1998.

         On February 22, 2000 the Board of Directors set the Company's indicated
annual dividend rate on common stock at $1.15 per share.

Electric Operations

         Electric  Operations  is comprised  of the  electric  portion of SCE&G,
GENCO  and  Fuel  Company.   Electric   operations   sales  margins,   including
transactions  with affiliates and excluding the cumulative  effect of accounting
change, for 2000, 1999 and 1998 were as follows:

Millions of dollars                2000            1999           1998
---------------------------------------------- ------------- ---------------

Operating revenues              $1,343.8       $1,226.0          $1,219.8

Less:  Fuel used in generation    (294.9)        (284.6)           (262.3)

           Purchased power         (82.5)         (35.9)            (31.5)
------------------------------------------- ---------------- ---------------
       Margin                     $966.4         $905.5            $926.0
=========================================== ================ ===============


o    2000 vs 1999     Sales margin increased primarily due to more favorable
                      weather and customer growth, which were
                      partially offset by higher purchased power costs.

o    1999 vs 1998    Sales margin decreased primarily due to the impact of a
                     rate reduction at SCE&G and milder weather,
                      which were partially offset by customer growth.


<PAGE>




     Increases  (decreases)  from the prior year in  megawatt-hour  (MWH)  sales
volume by classes,  excluding  volumes  attributable to the cumulative effect of
accounting change, were as follows:

Classification                  2000        % Change      1999      % Change
------------------------------------------- ----------- -----------------------

Residential                       396,179        6.3%     (55,207)   (0.9%)
Commercial                        354,350        6.0%      51,212     0.9%
Industrial                        524,969        8.5%    316,087      5.4%
Sales for Resale (excluding
  interchange)                     33,505        2.8%     63,306      5.6%
Other                              34,676        6.7%    (17,652)    (3.3%)
                               ----------                -------
-------------------------------
Total territorial               1,343,679        6.7%    357,746       1.8%
Negotiated Market Sales Tariff    264,257       15.7%    183,442      12.3%
                               -- -------                -------
-------------------------------
Total                          1,607,936        7.4%     541,188       2.6%
=========================================== =========== =======================

o    2000 vs 1999    Sales volume increased primarily due to more favorable
                     weather and customer growth.

o    1999 vs 1998    Sales volume decreased for residential primarily due to
                     milder weather, which was partially offset by
                     customer growth.  Volumes for the remaining classes
                     increased primarily due to customer growth.

Gas Distribution

      Gas  Distribution  is comprised of the local  distribution  operations  of
SCE&G and PSNC. Gas  distribution  sales margins,  including  transactions  with
affiliates and excluding the cumulative effect of accounting  change,  for 2000,
1999 and 1998 were as follows:

Millions of dollars                  2000           1999          1998
----------------------------------------------- ------------- -------------

Operating revenues                  $745.9         $239.0        $230.4
Less: Gas purchased for resale       (486.3)       (152.6)       (142.4)
----------------------------------------------- ------------- -------------
       Margin                       $259.6          $86.4          $88.0
=============================================== ============= =============

SCANA acquired PSNC  effective  January 1, 2000.  Therefore the Company's  prior
year sales do not include PSNC.

o     2000 vs 1999   Sales margin increased primarily due to the acquisition of
                     PSNC, which contributed $161.5 million,
                     and improved margin at SCE&G due primarily to more
                     favorable weather.

o     1999 vs 1998   Sales margin decreased primarily as a result of higher
                     gas costs.

      Increases  (decreases)  from the prior year in dekatherm (DT) sales volume
by classes,  including  transportation gas and excluding volumes attributable to
the cumulative effect of accounting change were as follows:

Classification          2000        % Change           1999         % Change
----------------------------------- -------------- -------------- -------------

Residential          23,541,979          199.1%        (94,027)        (0.8%)
Commercial           13,227,028          113.1%       404,654           3.6%
Industrial            4,478,371           24.9%       644,485           3.7%
Transportation gas   29,482,223       1,492.8%        (28,732)        (1.4%)
Sales for resale               407             -               -       -
                     -------------                 -------------
---------------------
Total                70,730,008         162.8%        926,380           2.2%
=================================== ============== ============== =============

o     2000 vs 1999    Sales volume increased primarily as a result of the
                      acquisition of PSNC, which accounted for 65.2
                      million DTs.  SCE&G's sales volume increased approximately
                      2.0 million DTs due to colder weather and
                      customer growth, which were partially offset by
                      curtailments and use of alternate fuels by
                      industrial customers.

o    1999 vs 1998    Sales volume increased primarily as a result of customer
                     growth.  Residential volume decreased primarily due to
                     milder weather.


<PAGE>



Gas Transmission

      Gas  Transmission is comprised of Pipeline  Corporation.  Gas transmission
sales margins for 2000, 1999 and 1998,  including  transactions with affiliates,
were as follows:

Millions of dollars                2000          1999           1998
-------------------------------------------- -------------- -------------

Operating revenues                $489.0        $342.4          $329.8
Less: Gas purchased for resale    (434.7)        (295.1)         (276.7)
-------------------------------------------- -------------- -------------
       Margin                      $54.3          $47.3           $53.1
============================================ ============== =============


o    2000 vs 1999     Sales margin  increased  primarily as a result
                      of increased  contract and sales volumes from the sale for
                      resale   classification   and  margin   earned   from  the
                      competitive industrial customers.

o    1999 vs 1998     Sales margin decreased primarily as a result of increased
                      competition with oil prices and a decrease
                      in the value of released capacity on the intrastate
                      pipeline system.

     Increases  (decreases)  from the prior year in dekatherms (DT) sales volume
by classes including transportation were as follows:

    Classification          2000        % Change         1999        % Change
    ----------------------------------- ---------------------------------------

    Commercial                22,132       24.2%            200        0.2%
    Industrial           (5,212,904)      (11.7%)      (916,235)      (2.0%)
    Transportation            10,296        0.5%       (179,029)      (7.4%)
    Sales for resale      3,542,185         6.0%      2,122,252         3.8%
    ===================================               ===========
    Total                (1,638,291)       (1.6%)     1,027,188         1.0%
    =================================== =======================================

o    2000 vs 1999    Sales for resale volumes increased as a result of colder
                     temperatures.  The sales volume for industrial customers
                     decreased due to decreased sales to electric generation
                     facilities and decreased sales to other customers with
                     alternate fuel sources.

o    1999 vs 1998    Sales volumes for sales for resale customers increased for
                     1999 as a result of customer growth and customer expansion
                     on our sale for resale customers' systems.  Transportation
                     and industrial volumes decreased due to increased
                     competition with oil prices.

Retail Gas Marketing

     Retail Gas  Marketing  is comprised  of SCANA  Energy,  a division of SCANA
Energy  Marketing,  Inc.,  which operates in Georgia's  deregulated  natural gas
market.  Retail gas  marketing  revenues and net income for 2000,  1999 and 1998
were as follows:

    Millions of dollars        2000             1999            1998
    -------------------------------------- --------------- ----------------

    Operating revenues        $547.3           $206.6           $3.5
    Net income (loss)            4.4            (44.8)         (7.9)
    -------------------------------------- --------------- ----------------


o                     2000 vs  1999Operating  revenues  increased as a result of
                      customer  growth,  favorable  weather and a successful gas
                      supply and pricing  strategy.  Net income  increased  as a
                      result  of  the   increase  in  revenue  and   significant
                      reductions  in  customer   acquisition   and   advertising
                      expenditures.

o    1999 vs 1998    Operating revenues increased as a result of a full year of
                     operations being reflected in 1999's results.  Net loss
                     increased as a result of large expenditures for marketing
                     and advertising reflected in 1999's results.

     Delivered  volumes  for  2000,  1999 and 1998  totaled  approximately  73.8
million,  40.9  million  and  0.5  million  DT,  respectively,   which  includes
interruptible  volumes of  approximately  30.6  million,  18.9  million  and 0.0
million DT for the same periods, respectively. The increases in volumes resulted
from customer growth.

Energy Marketing

     Energy  Marketing  is comprised of the  Company's  non-regulated  marketing
operations,  excluding SCANA Energy. Energy marketing operating revenues and net
losses for 2000, 1999 and 1998 were as follows:

    Millions of dollars            2000             1999            1998
    ------------------------------------------ --------------- ----------------

    Operating revenues            $543.3           $223.3          $564.6
    Net loss                        (4.2)            (3.9)           (6.6)
    ------------------------------------------ --------------- ----------------

o    2000 vs 1999Operating  revenues increased primarily due to increased prices
     for natural gas. Net loss increased primarily due to increased bad debts.

o                    1999  vs  1998Operating  revenues  and net  loss  decreased
                     primarily due to the closing of the Houston office.

     Delivered  volumes  for  2000,  1999 and 1998  totaled  approximately  83.9
million,  103.7  million and 218.5  million DT,  respectively.  The decreases in
volumes resulted from the closing of the Houston office.

Other Operating Expenses

     Increases in other operating expenses were as follows:

(Millions of dollars)            2000     % Change       1999       % Change
----------------------------------------- --------------------------------------

Other operation and maintenance   $66.1       16.1%        $60.4         17.2%
Depreciation and amortization      47.4       28.1%         24.3        16.8%

Other taxes                        10.6       10.3%          1.9        1.8%
=========================================             =============
Total                           $124.1        18.2%        $86.6         14.5%
========================================= ======================================


o    2000 vs 1999    Other operating expenses and taxes increased primarily as a
                     result of the acquisition of PSNC.  This acquisition
                     accounted for the following increases:  other operation and
                     maintenance ($67.5 million), depreciation and amortization
                     ($41.9 million, of which $13.4 million is attributable to
                     the amortization of the acquisition adjustment), and other
                     taxes ($6.4 million).

                     Apart  from  the  PSNC  acquisition,  other  operation  and
                      maintenance  expense decreased $1.4 million due to pension
                      income (see Earnings and  Dividends),  which was partially
                      offset  by  increased   maintenance   costs  for  electric
                      generating and distribution  facilities.  Depreciation and
                      amortization  increased  $5.5  million  primarily  due  to
                      normal  increases in utility plant.  Other taxes increased
                      $4.2 million primarily due to increased property taxes.

o    1999 vs 1998    Other operation and  maintenance increased primarily due to
                     costs associated with a cogeneration facility becoming
                     operational, costs associated with an early retirement
                     program and other operating costs.  These costs were
                     partially offset by pension income, which in 1998 had been
                     offset by the accelerated amortization of the electric
                     portion of the Company's transition obligation expense for
                     post-retirement benefits and other regulatory assets.
                     Depreciation and amortization increased primarily due to
                     the  impact of the non-recurring adjustment to depreciation
                     expense discussed under earnings and dividends, increased
                     amortization due to completion of a new customer billing
                     system and normal increases in utility plant. Other taxes
                     increased primarily due to increased property taxes.

Other Income

        Other income  decreased  approximately  $46.6  million for the year 2000
compared  to  1999,  primarily  as a  result  of  1999  including  the  sale  of
nonregulated propane assets and  telecommunications  towers, which was partially
offset by other  income at PSNC in 2000.  Other income  increased  approximately
$71.1 million for the year 1999  compared to 1998,  primarily as a result of the
sale of assets discussed previously and pension income.



<PAGE>



Interest Expense

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

    (Millions of dollars)               2000                1999
    ----------------------------------------------- --------------------

    Interest on long-term debt, net     $73.8                    $11.4
    Other interest expense               10.6                      3.9
    ----------------------------------------------- --------------------
        Total                           $84.4                    $15.3
    =============================================== ====================

o                     2000 vs  1999Interest  expense  increased  primarily  as a
                      result of financing  the  acquisition  of PSNC and related
                      repurchase  of SCANA shares  ($46.0  million) and interest
                      incurred  on PSNC debt that was assumed as a result of the
                      acquisition ($19.6 million). In addition, interest expense
                      increased  as  a  result  of  increased   borrowings   and
                      increased weighted average interest rates on long-term and
                      short-term borrowings.

o                     1999 vs  1998Interest  expense  increased  as a result  of
                      increased  long-term debt and increased  weighted  average
                      interest rates on long-term and short-term borrowings.

Income Taxes

         Income taxes  increased  approximately  $29.7 million for the year 2000
compared to 1999 and  decreased  approximately  $19.8  million for the year 1999
compared  to 1998.  Changes  in income  taxes are  primarily  due to  changes in
operating income.


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

     Interest  rate  risk - The  table  below  provides  information  about  the
Company's financial instruments that are sensitive to changes in interest rates.
For debt  obligations  the table  presents  principal  cash  flows  and  related
weighted average interest rates by expected maturity dates.
<TABLE>

    December 31, 2000                                                  Expected Maturity Date
    (Millions of dollars)

    Liabilities                        2001      2002       2003       2004       2005     Thereafter    Total     Fair Value
    -------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- --------------

      Long-Term Debt:
<S>              <C>                   <C>       <C>        <C>        <C>        <C>        <C>       <C>           <C>
      Fixed Rate ($)(1)                40.9      337.3      297.2      186.3      182.0      1,267.4   2,311.1       2,232.2

      Average Fixed Interest Rate      7.27%      7.36%      6.38%      7.58%      7.43%        7.35%     7.25%
      Variable Rate ($)                   -      550.0      150.0          -          -             -    700.0        699.7
      Average Variable Interest
    Rate                                  -       7.26%      7.48%         -          -             -     7.31%


    December 31, 1999                                                  Expected Maturity Date
    (Millions of dollars)

    Liabilities                        2000      2001      2002      2003        2004     Thereafter    Total      Fair Value
    -------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- --------------

      Long-Term Debt:
<S>              <C> <C>               <C>       <C>        <C>       <C>         <C>       <C>         <C>          <C>
      Fixed Rate ($) (1)               152.5     32.5       32.5      289.3       178.8     1,150.5     1,836.1      1,680.7

      Average Fixed Interest Rate       6.20%    6.85%     6.85%     6.17%         7.50%       7.33%       7.05%
      Variable Rate ($)                150.0        -         -          -            -           -       150.0        150.0
      Average   Variable   Interest
    Rate                               6.45%        -         -          -            -           -           -
</TABLE>

 (1) At December  31, 1999 there were no debt  issuances  outstanding  under the
$300 million credit agreement.  At December 31, 2000 the entire $300 million was
outstanding.

     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.


<PAGE>




     In  addition  the  Company has  invested  in a  telecommunications  company
approximately $40 million for 11.875 percent senior discount notes due 2007. The
fair value of these notes  approximates  cost.  An  increase in market  interest
rates  would  result  in  a  decrease  in  fair  value  of  these  notes  and  a
corresponding adjustment, net of tax effect, to other comprehensive income.

     Commodity  price  risk - The table  below  provides  information  about the
Company's  financial  instruments  that are  sensitive to changes in natural gas
prices. Weighted average settlement prices are per 10,000 mmbtu.

December 31, 2000                              Expected Maturity in
2001

(Millions of dollars)              Weighted Avg         Contract        Fair
Natural Gas Derivatives:           Settlement Price      Amount        Value
---------------------------------------------------- ------------- -------------

Future Contracts:
  Long                                  $6.5870          $57.2         $81.5
  Short                                 $6.2957            $1.4          $2.1
SET Futures Contracts (1):
    Long                                $6.5239            $2.8          $4.4
    Short                                        -             -             -

December 31, 1999                              Expected Maturity in
2000

(Millions of dollars)                Weighted Avg       Contract        Fair
Natural Gas Derivatives:             Settlement Price    Amount        Value
----------------------------------------------------- ------------ -------------

Future Contracts:
  Long                                    $2.3318         $20.0     $19.8
  Short                                   $2.3290           $1.2      $1.1
SET Futures Contracts (1):
  Long                                    $2.7161           $5.0      $5.1
  Short                                   $2.7461           $4.7      $4.8


     (1) SCANA Energy  Trading,  LLC (SET) is a 70 percent  owned  subsidiary of
SCANA Energy Marketing, Inc. Amounts shown are
at 100 percent.

     Equity price risk - Certain  investments in  telecommunications  companies'
marketable  equity  securities  are  carried  at their  market  value of  $597.8
million.  A ten percent  decline in market value would result in a $59.8 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.

  ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                   TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
                   STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA

                                                                           Page

  Independent Auditors' Report............................................. 43

  Consolidated Financial Statements:

  Consolidated Balance Sheets as of December 31, 2000 and 1999............. 44

  Consolidated Statements of Income and Retained Earnings
       for the Years Ended December 31, 2000, 1999 and 1998................ 46

  Consolidated Statements of Cash Flows for the Years Ended
       December 31, 2000, 1999 and 1998.................................... 47

  Consolidated Statements of Capitalization as of
       December 31, 2000 and 1999.......................................... 48

  Consolidated Statements of Changes in Common Equity for the Years
      Ended December 31, 2000, 1999 and 1998............................... 52

  Notes to Consolidated Financial Statements............................... 53


<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, 2000 and 1999
and the related Consolidated Statements of Income and Retained Earnings, Changes
in Common  Equity and Cash Flows for each of the three years in the period ended
December 31,  2000.  Our audits also include the  financial  statement  schedule
listed in Part IV at Item 14. These financial statements and financial statement
schedule are the responsibility of the Company's management.  Our responsibility
is to express an opinion on these financial  statements and financial  statement
schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit to obtain  reasonable  assurance  about  whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In our opinion,  such consolidated  financial  statements present fairly, in all
material  respects,  the financial  position of the Company at December 31, 2000
and 1999 and the  results of its  operations  and its cash flows for each of the
three years in the period ended December 31, 2000 in conformity  with accounting
principles  generally  accepted in the United  States of America.  Also,  in our
opinion,  such financial statement schedule,  when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

As  discussed  in Note 2 to the  consolidated  financial  statements,  effective
January 1, 2000,  the Company  changed its method of  accounting  for  operating
revenues associated with its regulated utility operations.


s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 2001 (February 16, 2001 as to Note 15)









<PAGE>


<TABLE>

      SCANA Corporation
     CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------- ------------------- ---------------------
December 31,  (Millions of dollars)                                                  2000                 1999
----------------------------------------------------------------------------- ------------------- ---------------------
Assets
Utility Plant (Notes 1 & 6):
<S>                                                                                 <C>                  <C>
    Electric                                                                        $4,747               $4,633
    Gas                                                                               1,435                  632
    Other                                                                               187                  191
----------------------------------------------------------------------------- ------------------- ---------------------
    Total                                                                            6,369                5,456
    Less accumulated depreciation and amortization                                   2,212                1,829
----------------------------------------------------------------------------- ------------------- ---------------------
    Total                                                                            4,157                3,627
    Construction work in progress                                                       261                  159
    Nuclear fuel, net of accumulated amortization                                        57                   43
    Acquisition adjustment-gas, net of accumulated amortization (Note 3)               474                    22
----------------------------------------------------------------------------- ------------------- ---------------------
    Utility Plant, Net                                                               4,949                3,851
----------------------------------------------------------------------------- ------------------- ---------------------

Nonutility Property, net of accumulated depreciation                                     79                   61
Investments (Note 12)                                                                  203                   938
----------------------------------------------------------------------------- ------------------- ---------------------
    Nonutility Property and Investments, net of accumulated depreciation               282                   999
----------------------------------------------------------------------------- ------------------- ---------------------

Current Assets:
    Cash and temporary cash investments (Notes 1 & 12)                                  159                  116
    Receivables  (net of provision for uncollectible
       accounts of $31 million in 2000 and $7 million in 1999)                          699                  318
    Inventories (At average cost) (Note 7):
        Fuel                                                                            107                   82
        Materials and supplies                                                            56                  51
        Emission allowances                                                               20                  17
    Prepayments                                                                          16                   18
    Investments (Note 12)                                                               479                     -
    Deferred income taxes, net  (Notes 1 & 11)                                             -                  16
----------------------------------------------------------------------------- ------------------- ---------------------
        Total Current Assets                                                         1,536                   618
----------------------------------------------------------------------------- ------------------- ---------------------

Deferred Debits:
    Emission allowances                                                                    3                  14
    Environmental                                                                         30                  24
    Nuclear plant decommissioning fund  (Note 1)                                          72                  64
    Pension asset, net  (Note 5)                                                        196                  144
    Other regulatory assets (Note 1)                                                    213                  175
    Other                                                                               139                  122
----------------------------------------------------------------------------- ------------------- ---------------------
        Total Deferred Debits                                                           653                  543
----------------------------------------------------------------------------- ------------------- ---------------------
            Total                                                                   $7,420                $6,011
============================================================================= =================== =====================


<PAGE>



                                                            169



     ----------------------------------------------------------------------- --------------------- ---------------------
     December 31,  (Millions of dollars)                                             2000                  1999
     ----------------------------------------------------------------------- --------------------- ---------------------
     Capitalization and Liabilities
     Stockholders' Investment:
<S>                           <C>                                                   <C>                   <C>
         Common Equity  (Note 9)                                                    $2,032                $2,099
         Preferred stock (Not subject to purchase or sinking funds) (Note
     10)                                                                                106                   106
     ----------------------------------------------------------------------- --------------------- ---------------------
             Total Stockholders' Investment                                          2,138                 2,205
     Preferred Stock, net (Subject to purchase or sinking funds)                         10                     11
     SCE&G-Obligated  Mandatorily  Redeemable  Preferred  Securities  of SCE&G's
         Subsidiary  Trust,  SCE&G Trust I, holding solely $50 million principal
         amount of the 7.55% Junior Subordinated
         Debentures of SCE&G, due 2027 (Note 10)                                         50                    50
     Long-Term Debt, net  (Notes 6 & 12)                                             2,850                 1,563
     ----------------------------------------------------------------------- --------------------- ---------------------
             Total Capitalization                                                    5,048                 3,829
     ----------------------------------------------------------------------- --------------------- ---------------------

     Current Liabilities:
         Short-term borrowings  (Notes 7, 8 & 12)                                      398                    266
         Current portion of long-term debt  (Note 6)                                    41                   303
         Accounts payable                                                              396                    189
         Customer deposits                                                              25                     16
         Taxes accrued                                                                  54                     86
         Interest accrued                                                               42                     29
         Dividends declared                                                             32                     31
         Deferred income taxes, net  (Notes 1 & 11)                                     98                      -
         Other                                                                          25                     13
     ----------------------------------------------------------------------- --------------------- ---------------------
            Total Current Liabilities                                                1,111                    933
     ----------------------------------------------------------------------- --------------------- ---------------------

     Deferred Credits:
         Deferred income taxes, net  (Notes 1 & 11)                                    721                    805
         Deferred investment tax credits (Notes 1 & 11)                                119                    116
         Reserve for nuclear plant decommissioning  (Note 1)                            72                    64
         Postretirement benefits  (Note 5)                                             113                     98
         Other regulatory liabilities                                                   75                    64
         Other (Note 1)                                                                161                   102
     ----------------------------------------------------------------------- --------------------- ---------------------
             Total Deferred Credits                                                  1,261                 1,249
     ----------------------------------------------------------------------- --------------------- ---------------------

     Commitments and Contingencies (Note 13)                                            -                     -
     ----------------------------------------------------------------------- --------------------- ---------------------

                Total                                                               $7,420                $6,011
     ======================================================================= ===================== =====================

    See Notes to Consolidated Financial Statements.













<PAGE>







SCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
-------------------------------------------------------------------------- ---------------- --------------- -------------- --
For the Years Ended December 31,                                                2000             1999           1998
-------------------------------------------------------------------------- ---------------- --------------- -------------- --
(Millions of Dollars, except per share amounts)

Operating Revenues (Notes 1, 2 & 4):
<S>                                                                            <C>               <C>               <C>
    Electric                                                                   $1,344            $1,226            $1,220
    Gas - Regulated                                                                998            422              411
    Gas - Nonregulated                                                           1,091            430               475
-------------------------------------------------------------------------- ---------------- --------------- ----------------
        Total Operating Revenues                                                3,433           2,078            2,106
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Operating Expenses:
    Fuel used in electric generation                                               295            285              262
    Purchased power                                                                 82             36                31
    Gas purchased for resale                                                    1,694             721              746
    Other operation and maintenance (Note 1)                                       477            411              351
    Depreciation and amortization (Note 1)                                         217            169              145
    Other taxes                                                                    114            103              101
-------------------------------------------------------------------------- ---------------- --------------- ----------------
        Total Operating Expenses                                                2,879           1,725            1,636
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Operating Income                                                                  554             353              470
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Other Income:
    Other income, including allowance for equity funds
       used during construction (Note 1)                                            41              22               19
    Gain on sale of subsidiary assets                                                3              68                -
-------------------------------------------------------------------------- ---------------- --------------- ----------------
        Total Other Income                                                         44               90              19
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Interest Charges, Income Taxes, Preferred Stock
   Dividends and Cumulative Effect of Accounting Change                           598             443              489
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Interest Charges:
    Interest expense on long-term debt, net                                       206              132             121
    Other interest expense, net of allowance for borrowed funds
       used during construction (Note 1)                                           19               10                2
-------------------------------------------------------------------------- ---------------- --------------- ----------------
        Total Interest Charges, Net                                               225             142              123
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Income Taxes, Preferred Stock Dividends
   and Cumulative Effect of Accounting Change                                     373               301            366
Income Taxes (Note 11)                                                            141              111             131
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Preferred Stock Dividends and Cumulative
    Effect of Accounting Change                                                   232             190              235
Preferred Dividend Requirement of SCE&G - Obligated Mandatorily
    Redeemable Preferred Securities                                                  4               4               4
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Cash Dividends on Preferred Stock  of Subsidiary
   and Cumulative Effect of Accounting Change                                      228            186             231
Cash Dividends on Preferred Stock of Subsidiary (At stated rates)                     7              7               8
-------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Cumulative Effect of Accounting Change                               221            179             223
Cumulative Effect of Accounting Change, net of taxes  (Note 2)                      29               -               -
-------------------------------------------------------------------------- ---------------- --------------- ----------------

Net Income                                                                         250             179            223
Retained Earnings at Beginning of Year                                             720            678             617
Common Stock Cash Dividends Declared                                              (120)          (137)           (162)
========================================================================== ================ =============== ================
Retained Earnings at End of Year                                                 $850               $720             $678
========================================================================== ================ =============== ================
Basic and Diluted Earnings Per  Share of Common Stock:
   Before Cumulative Effect of Accounting Change                                $2.12              $1.73            $2.12
   Cumulative Effect of Accounting Change, net of taxes  (Note 2)                  .28               -               -
========================================================================== ================ =============== ================
   Basic and diluted earnings per share                                         $2.40              $1.73            $2.12
========================================================================== ================ =============== ================
Weighted average shares outstanding (millions)                                  104.5              103.6            105.3
========================================================================== ================ =============== ================

See Notes to Consolidated Financial Statements.



<PAGE>










SCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, (Millions of dollars)                             2000          1999         1998
------------------------------------------------------------------------------ -------------- ------------ ------------

Cash Flows From Operating Activities:
<S>                                                                                <C>           <C>            <C>
Net income                                                                         $250          $179           $223
Adjustments to reconcile net income to net cash provided from operating
activities:
    Cumulative effect of accounting change, net of taxes                             (29)             -           -
    Depreciation and amortization                                                    227           177            152
    Amortization of nuclear fuel                                                      16            18          20
    Gain on sale of subsidiary assets                                                 (3)          (68)           -
    Equity in losses of affiliates                                                     3              1           -
    Preferred stock dividends                                                          7             7            8
    Allowance for funds used during construction                                      (9)           (7)        (16)
    Over (under) collection, fuel adjustment clauses                                 (33)          (6)            1
    Changes in certain assets and liabilities:
         Increase in receivables                                                   (263)           (42)        (28)
         Increase  in deferred income taxes, net                                      61            19          15
         Increase in pension asset                                                   (43)          (29)        (33)
         Increase  in postretirement benefits                                         15            11          26
         Decrease in other regulatory assets                                           4            19          16
         Increase (decrease) in other regulatory liabilities                          11            (7)           4
         (Increase) decrease in inventories                                            3          (14)         (16)
         Increase (decrease) in accounts payable                                    157           (30)          88
         Increase (decrease) in taxes accrued                                       (55)           14           13
   Other, net                                                                        72           (17)           (6)
------------------------------------------------------------------------------ -------------- ------------ ------------
Net Cash Provided From Operating Activities                                         391           225          467
------------------------------------------------------------------------------ -------------- ------------ ------------
Cash Flows From Investing Activities:
  Utility property additions and construction expenditures, net of AFC             (334)         (238)        (281)
  Purchase of subsidiary, net of cash acquired                                     (212)             -            -
  Proceeds on sale of subsidiary assets                                                8          112             -
  Increase in nonutility property and investments, net:
     Nonutility property                                                            (27)          (23)          (22)
     Investments                                                                    (20)          (74)        (106)
------------------------------------------------------------------------------ -------------- ------------ ------------
Net Cash Used For Investing Activities                                             (585)         (223)        (409)
------------------------------------------------------------------------------ -------------- ------------ ------------
Cash Flows From Financing Activities:
    Proceeds:
        Issuance of First Mortgage Bonds                                            148            99             -
        Issuance of notes and loans                                                 998           200          249
    Repayments and repurchases:
        Mortgage bonds                                                             (100)          (10)         (50)
        Notes and loans                                                            (175)          (77)         (96)
        Other long-term debt                                                          (8)         (10)            -
        Preferred stock                                                               (1)            -           (1)
        Common stock                                                               (488)             -        (110)
    Dividend payments:
        Common Stock                                                               (124)         (148)        (162)
        Preferred stock                                                               (7)           (7)          (8)
    Short-term borrowings, net                                                        (6)           71         136
    Fuel financings, net                                                               -           (66)        (14)
------------------------------------------------------------------------------ -------------- ------------ ------------
Net Cash Provided From (Used For) Financing Activities                              237             52         (56)
------------------------------------------------------------------------------ -------------- ------------ ------------
Net Increase in Cash and Temporary Cash Investments                                   43            54            2
Cash and Temporary Cash Investments, January 1                                      116             62           60
============================================================================== ============== ============ ============
Cash and Temporary Cash Investments, December 31                                   $159          $116         $ 62
============================================================================== ============== ============ ============

Supplemental Cash Flow Information:
Cash paid for   - Interest (net of capitalized interest of  $6, $4 and $7)         $207          $138         $120
                         - Income taxes                                              139            84         114
Noncash Investing and Financing Activities:
   Unrealized gain (loss) on securities available for sale, net of tax             (197)           311            7
   In conjunction with the acquisition of Public Service Company of North Carolina, Incorporated, liabilities were
assumed as follows:
         Fair value of assets acquired                  $1,177
         Cash paid for capital stock                        (212)
         Stock issued as consideration                    (488)
                                                     ---------
             Liabilities assumed                               $477

See Notes to Consolidated Financial Statements.


<PAGE>












SCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION

--------------------------------------------------------------------------------- ------------- ------ ------------- ------
December 31, (Millions of dollars)                                                        2000                 1999
--------------------------------------------------------------------------------- ------------- ------ ------------- ------

Common Equity (Note 9):
  Common stock, without par value, authorized 150,000,000 shares; issued and
outstanding,
<S>  <C>                   <C>      <C>                   <C>                           <C>                  <C>
     104,729,131 shares in 2000 and 103,572,623 shares in 1999                          $1,043               $1,043
  Unrealized gain on securities available for sale, net of taxes                           139                  336
  Retained earnings                                                                        850                  720
--------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Common Equity                                                                      2,032    40%         2,099    55%
--------------------------------------------------------------------------------- ------------- ------ ------------- ------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds):

        $100 Par Value - Authorized 1,200,000 shares
          $50 Par Value - Authorized 125,209 shares
                                             Shares
                             Outstanding                    Redemption Price

                   Series           2000         1999
                   ------           ----         ----
        $100
Par                6.52%       1,000,000    1,000,000            100.00                    100                  100
          $50
Par                5.00%         125,209      125,209              52.50                     6                    6
--------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Preferred Stock (Not subject to purchase or sinking funds) (Note 10)                 106     2%           106     3%
--------------------------------------------------------------------------------- ------------- ------ ------------- ------

South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase and sinking funds):

       $100 Par Value - Authorized  1,550,000  shares;  None outstanding in 2000
         and 1999 $50 Par Value - Authorized 1,560,287 shares

                                 Shares Outstanding          Redemption Price

                    Series          2000         1999
                    ------          ----         ----

                       4.50%       9,600       11,200             51.00                      1                    1
                     4.60% (A)    16,052       18,052             51.00                      1                    1
                       4.60%
                      (B)         57,800       61,200             50.50                      3                    3
                     5.125%       67,000       68,000             51.00                      3                    3
                     6.00%        69,835       73,035             50.50                      3                    4
                                --------- ------------
          Total                  220,287      231,487
                                ========= ============

           $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999

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

Total Preferred Stock  (Subject to purchase or sinking funds)                          11                    12

Less:  Current portion, including sinking fund requirements                            (1)                  (1)
---------------------------------------------------------------------------------- ------------ -------- ----------- -------

Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 10 & 12)      10           -%       11         -%
---------------------------------------------------------------------------------- ------------ -------- ----------- -------

SCE&G-Obligated   Mandatorily   Redeemable   Preferred   Securities  of  SCE&G's
   Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount

   of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 10)                50            1%      50          1%
---------------------------------------------------------------------------------- ------------ -------- ----------- -------



<PAGE>

















     -------------------------------------------------------------------- -- -------------- -------- -------------- -----------
     December 31,  (Millions of dollars)                                              2000                    1999
     -------------------------------------------------------------------- -- -------------- -------- -------------- -----------
     Long-Term Debt  (Notes 6 & 12)

     SCANA Corporation:
        Medium-Term Notes:                Series      Year of Maturity
<S>                                       <C>               <C>                     <C>                    <C>
                                          5.52%             2000                      -                     150
                                          6.15%             2000                      -                      20
                                          7.45%             2002                    300                       -
                                          5.91%(1)          2002                    400                       -
                                          6.51%             2003                     20                      20
                                          6.05%             2003                     60                      60
                                          6.25%             2003                     75                      75
                                          7.44%             2004                     50                      50
                                          6.90%             2007                     25                      25
                                          5.81%             2008                    115                     115

     (1)  Current rate, based on LIBOR, reset quarterly

     Bank note, due 2002-2003, LIBOR rate, reset 1, 2, 3 or 6 months,
        currently 6.57%                                                             300                        -

     South Carolina Electric & Gas Company:
        First Mortgage Bonds:              Series      Year of Maturity
                                           6%                2000                      -                    100
                                           6 1/4%            2003                   100                     100
                                           7.70%             2004                   100                     100
                                           7 1/2%            2005                   150                        -
                                           6 1/8%            2009                   100                     100
                                           7 1/8%            2013                   150                     150
                                           7 1/2%            2023                   150                     150
                                           7 5/8%            2023                   100                     100
                                           7 5/8%            2025                   100                     100

        First and Refunding Mortgage
     Bonds:                                Series      Year of Maturity
                                           9%                2006                    131                    131
                                           8 7/8%            2021                    103                    103

        Pollution Control Facilities Revenue Bonds:
           Fairfield County Series 1984, due 2014 (6.50%)                            57                      57
           Orangeburg County Series 1994, due 2024 (5.70%)                           30                      30
           Other                                                                     17                      17
        Charleston Franchise Agreement due 1997-2002                                   7                     11
     South Carolina Generating Company, Inc.:
           Berkeley County Pollution Control Facilities Revenue
              Bonds, Series 1984 due 2014 (6.50%)                                    36                      36
           Note, 7.78%, due 2011                                                     49                      49
     Public Service Company of North Carolina, Incorporated:
           Senior Debentures:             Series      Year of Maturity
                                          10%               2004                     17                        -
                                          8.75%             2012                     32                        -
                                          6.99%             2026                     50                        -
                                          7.45%             2026                     50                        -
     South Carolina Pipeline Corporation Notes, 6.72%, due 2013                      16                      17
     Other                                                                            4                        3
     -------------------------------------------------------------------- -- -------------- -------- -------------- -----------
     Total Long-Term Debt                                                        2,894                   1,869
     Less  -  Current maturities, including sinking fund requirements               (41)                   (303)
              -  Unamortized discount                                                 (3)                     (3)
     -------------------------------------------------------------------- -- -------------- -------- -------------- -----------
     Total Long-Term Debt, Net                                                   2,850          57%      1,563          41%
     -------------------------------------------------------------------- -- -------------- -------- -------------- -----------
     Total Capitalization                                                       $5,048         100%     $3,829         100%
     ==================================================================== == ============== ======== ============== ===========
     See Notes to Consolidated Financial Statements.


<PAGE>





SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY

----------------- ------------- -- --------- ------------------ ------------- ---------------- ----------- --------------
For the Years Ended December
31,                                           2000                          1999                         1998
------------------------------- -- ---------------------------- ------------------------------ --------------------------
(Millions of dollars)


                                     Common     Comprehensive      Common      Comprehensive     Common    Comprehensive
                                     Equity        Income          Equity         Income         Equity       Income
----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Retained
Earnings:
   Balance at
January 1                             $720                           $678                         $617
<S>                                     <C>         <C>               <C>          <C>             <C>         <C>
   Net Income                           250         $250              179          $179            223         $223
   Dividends declared on common
stock                                  (120)                         (137)                        (162)
---------------------------------- ----------- ---------------- ------------- ---------------- ----------- --------------
   Balance at December 31              850                            720                           678
------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------

Accumulated other comprehensive income:
  Balance at
January 1                              336                             25                            18
  Unrealized gains (losses)
on securities,
     net of taxes ($(106),
$165 and $4 in
     2000, 1999 and 1998,
respectively)                         (197)         (197)             311            311              7            7
------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
  Comprehensive income                               $53                           $490                        $230
------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
  Balance at
December 31                            139                            336                            25
----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------

Common Stock:
  Balance at
January 1                            1,043                          1,043                         1,153
  Shares issued                         488                              -                             -
  Shares
repurchased                           (488)                          -                             (110)
----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
  Balance at
December 31                          1,043                          1,043                         1,043
----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------

Total Common
Equity                               $2,032                        $2,099                        $1,746
================= ============= == =========== ================ ============= ================ =========== ==============
</TABLE>

Accumulated other  comprehensive  income at December 31, 2000, 1999 and 1998 was
comprised of unrealized  holding gains and losses on  securities,  net of taxes.
There were no realized gains or losses from these securities for the years ended
December 31, 2000, 1999 and 1998.



See Notes to Consolidated Financial Statements.



<PAGE>



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.  Organization and Principles of Consolidation

         SCANA  Corporation  (Company),  a  South  Carolina  corporation,  is  a
registered  public  utility  holding  company  within the  meaning of the Public
Utility Holding Company Act of 1935 (PUHCA).  The Company,  through wholly owned
subsidiaries, is engaged predominately in the generation and sale of electricity
to wholesale and retail  customers in South  Carolina and in the purchase,  sale
and  transportation  of natural gas to wholesale  and retail  customers in South
Carolina,  North  Carolina  and  Georgia.  The Company is also  engaged in other
energy-related  businesses.  The Company has  investments in  telecommunications
companies and provides fiber optic communications in South Carolina.

         The accompanying Consolidated Financial Statements reflect the accounts
of the Company and its wholly owned subsidiaries:

Regulated utilities                               Nonregulated businesses
South Carolina Electric & Gas Company (SCE&G)     SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc. (Fuel Company)  SCANA Communications, Inc.
                                                   (SCI)
South Carolina Generating Company, Inc. (GENCO)   ServiceCare, Inc.
South Carolina Pipeline Corporation               Primesouth, Inc.
   (Pipeline Corporation)                         SCANA Resources, Inc.
Public Service Company of North Carolina,         SCANA Services, Inc.
   Incorporated (PSNC)                            SCANA Propane Gas, Inc.
                                                   (in liquidation)
                          SCANA Propane Services, Inc.
                                (in liquidation)
  SCANA Petroleum Resources, Inc. (in liquidation)
  SCANA Development Corporation (in liquidation)

         Certain  investments  are reported  using the cost or equity  method of
accounting,  as appropriate.  Significant intercompany balances and transactions
have been  eliminated  in  consolidation  except as  permitted  by  Statement of
Financial  Accounting  Standards  (SFAS) 71 ,  "Accounting  for the  Effects  of
Certain Types of Regulation"  which provides that profits on intercompany  sales
to regulated  affiliates are not eliminated if the sales price is reasonable and
the future  recovery  of the sales  price  through  the  rate-making  process is
probable.

B.  Basis of Accounting

         The Company accounts for its regulated utility  operations,  assets and
liabilities  in  accordance  with the  provisions  of SFAS 71.  This  accounting
standard  requires  cost-based  rate-regulated  utilities  to recognize in their
financial  statements  revenues and  expenses in different  time periods than do
enterprises that are not  rate-regulated.  As a result the Company has recorded,
as of  December  31,  2000,  approximately  $243  million  and  $75  million  of
regulatory assets and liabilities,  respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $140 million and $57
million,  respectively.  The electric and gas regulatory assets of approximately
$45  million  and $58  million,  respectively  (excluding  deferred  income  tax
assets),  are  recoverable  through  rates.  In  the  future,  as  a  result  of
deregulation or other changes in the regulatory environment,  the Company may no
longer  meet the  criteria  for  continued  application  of SFAS 71 and could be
required to write off its regulatory assets and liabilities. Such an event could
have a material  adverse  effect on the  Company's  results of operations in the
period the write-off  would be recorded,  but it is not expected that cash flows
or financial position would be materially affected.

C.  System of Accounts

         The  accounting  records of the Company's  regulated  subsidiaries  are
maintained  in  accordance  with the Uniform  System of Accounts  prescribed  by
either  the  Federal  Energy  Regulatory   Commission  (FERC)  or  the  National
Association of Regulatory  Utility  Commissioners  (NARUC) and as adopted by the
Public  Service  Commission of South Carolina (PSC) or, in the case of PSNC, the
North  Carolina  Utilities  Commission  (NCUC).  The NARUC system of accounts is
substantially the same as the FERC system of accounts.


<PAGE>



D.  Utility Plant

         Utility plant is stated  substantially  at original  cost. The costs of
additions,  renewals and betterments to utility plant,  including  direct labor,
material and indirect charges for engineering,  supervision and an allowance for
funds  used  during  construction,  are added to  utility  plant  accounts.  The
original cost of utility  property  retired or otherwise  disposed of is removed
from  utility  plant  accounts  and  generally  charged,  along with the cost of
removal,  less  salvage,  to  accumulated  depreciation.  The costs of  repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.

         SCE&G,  operator of the V. C. Summer Nuclear Station (Summer  Station),
and the South Carolina Public Service Authority (Santee Cooper) are joint owners
of Summer Station in the proportions of two-thirds and one-third,  respectively.
The parties  share the  operating  costs and energy output of the plant in these
proportions.  Each party, however, provides its own financing.  Plant-in-service
related to SCE&G's  portion of Summer Station was  approximately  $965.0 million
and $959.7 million as of December 31, 2000 and 1999,  respectively.  Accumulated
depreciation  associated with SCE&G's share of Summer Station was  approximately
$387.7   million  and  $365.1   million  as  of  December  31,  2000  and  1999,
respectively.  SCE&G's share of the direct  expenses  associated  with operating
Summer Station is included in "Other operation and maintenance" expenses.

E.   Allowance for Funds Used During Construction (AFC)

         AFC, a noncash  item,  reflects  the period cost of capital  devoted to
plant under construction.  This accounting practice results in the inclusion of,
as a  component  of  construction  cost,  the costs of debt and  equity  capital
dedicated to  construction  investment.  AFC is included in rate base investment
and depreciated as a component of plant cost in  establishing  rates for utility
services.  The Company's regulated  subsidiaries  calculated AFC using composite
rates of 8.3%, 8.1% and 8.7% for 2000, 1999 and 1998, respectively.  These rates
do not exceed the maximum allowable rate as calculated under FERC Order No. 561.
Interest on nuclear fuel in process is capitalized at the actual interest amount
incurred.

F.   Revenue Recognition

         Revenues are recorded  during the  accounting  period in which services
are provided to customers,  and include  estimated  amounts for  electricity and
natural gas  delivered,  but not yet billed.  Prior to January 1, 2000  revenues
related to regulated  electric and gas services  were recorded only as customers
were billed (see Note 2).

         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 PSC 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  $35.5 million and $10.1 million at
December 31, 2000 and 1999, respectively, which are included in "Deferred Debits
- Other regulatory assets."

         Customers subject to the gas cost adjustment clause are billed based on
a fixed  cost of gas  determined  by the PSC  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,  2000  and  1999  the  Company  had
undercollected  through  the gas cost  recovery  procedure  approximately  $22.0
million and $4.1 million,  respectively,  which are included in "Deferred Debits
Other regulatory assets."

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

G.  Depreciation and Amortization

         Provisions for  depreciation  and  amortization  are recorded using the
straight-line method and are based on the estimated service lives of the various
classes of property.



<PAGE>




The composite weighted average  depreciation rates for utility plant assets were
as follows:


                        2000            1999            1998
---------------------------------- --------------- ---------------
SCE&G                   2.98%             2.99%           3.02%
GENCO                   2.67%             2.56%           2.65%
Pipeline Corporation    2.58%             2.62%           2.63%
PSNC                    4.15%              -               -
Aggregate of Above      3.09%             2.95%           2.98%

       Nuclear  fuel  amortization,  which is included in "Fuel used in electric
generation"  and recovered  through the fuel cost component of SCE&G's rates, is
recorded using the  units-of-production  method.  Provisions for amortization of
nuclear fuel include amounts necessary to satisfy  obligations to the Department
of Energy (DOE) under a contract for disposal of spent nuclear fuel.

       The  acquisition  adjustment  relating  to the  purchase  of certain  gas
properties  in  1982  is  being  amortized  over  a  40-year  period  using  the
straight-line method. The acquisition adjustment related to the purchase of PSNC
in 2000 is being amortized over a 35-year period using the straight-line method.

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 ownership
interest  in the  station.  The cost  estimate  is  based  on a  decommissioning
methodology  acceptable to the Nuclear  Regulatory  Commission (NRC) under which
the site would be maintained over a period of  approximately  60 years in such a
manner as to allow for  subsequent  decontamination  that  permits  release  for
unrestricted use.

       SCE&G's method of funding  decommissioning costs is referred to as COMReP
(Cost of Money Reduction Plan).  Under this plan, funds collected  through rates
($3.2  million  in each of 2000,  1999 and  1998)  are used to pay  premiums  on
insurance  policies  on the lives of  certain  Company  personnel.  SCE&G is the
beneficiary of these policies.  Through these insurance contracts, SCE&G is able
to take  advantage of income tax  benefits and accrue  earnings on the fund on a
tax-deferred  basis.  Amounts for  decommissioning  collected  through  electric
rates,  insurance  proceeds,  and  interest  on  proceeds,  less  expenses,  are
transferred by SCE&G to an external trust fund in compliance  with the financial
assurance  requirements of the NRC.  Management intends for the fund,  including
earnings thereon, to provide for all eventual decommissioning expenditures on an
after-tax  basis.  SCE&G  records its  liability  for  decommissioning  costs in
deferred credits.

       In addition  to the above,  pursuant to the  National  Energy  Policy Act
passed by Congress in 1992 and the requirements of the DOE, SCE&G has recorded a
liability   for  its   estimated   share  of  the  DOE's   decontamination   and
decommissioning  obligation.  The  liability,   approximately  $2.8  million  at
December  31,  2000,  has been  included  in  "Long-Term  Debt,  net."  SCE&G is
recovering  the cost  associated  with  this  liability  through  the fuel  cost
component  of its  rates;  accordingly,  this  amount has been  deferred  and is
included in "Deferred Debits - Other."

I.  Income Taxes

       The  Company  files  a  consolidated  income  tax  return.  Under a joint
consolidated  income tax allocation  agreement,  each  subsidiary's  current and
deferred tax expense is computed on a stand-alone basis. Deferred tax assets and
liabilities  are  recorded  for the tax  effects  of all  significant  temporary
differences  between the book basis and tax basis of assets and  liabilities  at
currently  enacted tax rates.  Deferred tax assets and  liabilities are adjusted
for changes in such rates  through  charges or credits to  regulatory  assets or
liabilities  if they are expected to be recovered  from,  or passed  through to,
customers of the Company's regulated subsidiaries;  otherwise,  they are charged
or credited to income tax expense.


<PAGE>




J.   Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt

        Long-term  debt  premium,  discount  and expense are being  amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues.  Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.

K.   Environmental

        The Company  maintains an environmental  assessment  program to identify
and assess current and former operations sites that could require  environmental
cleanup.  As  site  assessments  are  initiated,   estimates  are  made  of  the
expenditures,  if any, deemed  necessary to investigate and remediate each site.
These  estimates  are  refined  as  additional  information  becomes  available;
therefore,  actual  expenditures  could differ  significantly  from the original
estimates.  Amounts  estimated  and  accrued  to date for site  assessments  and
cleanup relate primarily to regulated operations.  Such amounts are deferred and
amortized with recovery  provided  through rates. The Company also has recovered
portions of its  environmental  liabilities  through  settlements  with  various
insurance  carriers,  including all amounts previously deferred for its electric
operations.  The Company  expects to recover  all  deferred  amounts  related to
SCE&G's gas  operations by December  2005.  Deferred  amounts for SCE&G,  net of
amounts recovered through rates and insurance settlements, totaled $20.2 million
and $23.7 million at December 31, 2000 and 1999, respectively.  Deferred amounts
for PSNC totaled $10.2 million at December 31, 2000.  The deferral  includes the
estimated costs associated with the matters discussed in Note 13C.

L.  Temporary Cash Investments

        The  Company  considers   temporary  cash  investments  having  original
maturities  of  three  months  or less to be cash  equivalents.  Temporary  cash
investments  are  generally in the form of  commercial  paper,  certificates  of
deposit and repurchase agreements.

M.  Commodity Derivatives

        To minimize price risk due to market fluctuations,  the Company utilizes
forward contracts,  futures  contracts,  option contracts and swap agreements to
hedge certain purchases and sales of natural gas. Changes in the market value of
such financial contracts pertaining to nonregulated  operations are deferred and
included in income in the period in which the offsetting  physical  transactions
occur.  For such  transactions  related to the Company's  regulated  operations,
gains and losses on these  contracts  are included as a component of the related
cost of gas which is subject to recovery under the fuel adjustment clause.  (See
Note 1F).  The  resulting  under or over  recovery  of such costs is recorded in
"Deferred Debits" or "Deferred Credits," respectively, on the balance sheet.

N.  Recently Issued Accounting Standard and Bulletin

         In June 1998 the  Financial  Accounting  Standards  Board (FASB) issued
SFAS 133,  "Accounting for Derivative  Instruments  and Hedging  Activities." In
June 2000, the FASB issued SFAS 138, which amends certain provisions of SFAS 133
to expand the normal  purchase and sale  exemption  for supply  contracts and to
redefine  interest rate risk to reduce sources of  ineffectiveness,  among other
things.  The  Company  utilizes  various  derivatives  in  its  risk  management
activities,  including swaps and commodities  futures.  The Company adopted SFAS
133,  as amended,  on January 1, 2001.  As a result of  adopting  SFAS 133,  the
Company  recorded a credit of  approximately  $23.0 million,  net of tax, as the
effect of a change in  accounting  principle  (transition  adjustment)  to other
comprehensive   income  on  January  1,  2001.   This  amount   represents   the
reclassification  of  unrealized  gains  that  were  deferred  and  reported  as
liabilities  at December 31, 2000. In the future,  all  gains/losses  related to
qualifying  cash flow  hedges  deferred  in other  comprehensive  income will be
reclassified to earnings at the time the hedged transaction affects earnings.

       In December 1999 Staff Accounting Bulletin No. 101, "Revenue  Recognition
in Financial  Statements"  was issued by the Securities and Exchange  Commission
(SEC),  and  provides  the SEC  staff's  views in  applying  generally  accepted
accounting  principles to selected  revenue  recognition  issues.  The Company's
adoption  of this  bulletin  in the fourth  quarter of 2000 had no impact on its
results of operations, cash flows or financial position.

O.  Stock Option Plan

        On April 27, 2000 the Company  adopted the SCANA  Corporation  Long-Term
Equity  Compensation  Plan (the Plan).  Under the Plan,  certain  employees  and
non-employee directors may receive nonqualified stock options and other forms of
equity  compensation.  The Company accounts for this  equity-based  compensation
under Accounting  Principles Board Opinion No. 25,  "Accounting for Stock Issued
to  Employees"  (APB 25).  In addition  the  Company has adopted the  disclosure
provisions of SFAS 123, "Accounting for Stock-Based Compensation."

P.  Earnings Per Share

        Earnings per share amounts have been  computed in  accordance  with SFAS
128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed
by  dividing  net  income  by the  weighted  average  number  of  common  shares
outstanding  for the  period.  Diluted  earnings  per share are  computed as net
income  divided  by the  weighted  average  number of  shares  of  common  stock
outstanding during the period after giving effect to securities considered to be
dilutive  potential  common stock. The Company uses the treasury stock method in
determining total dilutive potential common stock.

Q.  Reclassifications

        Certain  amounts from prior  periods have been  reclassified  to conform
with the presentation adopted for 2000.

R.  Use of Estimates

        The  preparation  of financial  statements in conformity  with generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.

2.      Cumulative Effect of Accounting Change

        Effective  January 1, 2000 the Company  changed its method of accounting
for operating  revenues  associated with its regulated  utility  operations from
cycle  billing to full  accrual.  The  cumulative  effect of this change was $29
million,  net of tax.  Accruing  unbilled revenues more closely matches revenues
and expenses. Unbilled revenues represent the estimated amount customers will be
charged for service  rendered but not yet billed as of the end of the accounting
period.

        If this method had been  applied  retroactively,  net income  would have
been $181 million  ($1.75 per share) and $216 million  ($2.05 per share) for the
years ended December 31, 1999 and 1998,  respectively,  compared to $179 million
($1.73 per share) and $223 million ($2.12 per share), respectively, as reported.

3.      ACQUISITION

        On February 10, 2000 the Company  completed its acquisition of PSNC in a
business  combination  accounted  for as a purchase.  PSNC became a wholly owned
subsidiary  of the  Company.  PSNC is a  public  utility  engaged  primarily  in
transporting,  distributing  and selling  natural gas to  approximately  370,000
residential,  commercial  and  industrial  customers in 25 of its 28  franchised
counties in North Carolina.  Pursuant to the Agreement and Plan of Merger,  PSNC
shareholders  were paid  approximately  $212  million  in cash and 17.4  million
shares of SCANA common stock valued at approximately $488 million. In connection
with the acquisition, 16.3 million shares of SCANA common stock were repurchased
for approximately  $488 million.  The results of operations of PSNC are included
in the  accompanying  financial  statements as of January 1, 2000, the effective
date of acquisition . The total cost of the acquisition was  approximately  $700
million,   which  exceeded  the  fair  value  of  the  net  assets  acquired  by
approximately  $466 million.  The excess is being  amortized  over 35 years on a
straight-line basis.

The  following  represents  the unaudited pro forma results of operations of the
Company for 1999 as if the acquisition  were consummated on January 1, 1999. The
unaudited pro forma results of operations  exclude the effects of the accounting
change discussed in Note 2 and include certain pro forma adjustments,  including
the  amortization  of the  acquisition  adjustment  and interest on  acquisition
financing.  The unaudited  pro forma  results of  operations do not  necessarily
reflect the results  that would have  occurred had the  acquisition  occurred at
January 1, 1999 or the results that may occur in the future.

In millions of dollars, except per share amount
----------------------------------------------------------- ------------------
Operating revenues                                          $2,385
Net income                                                     163
Basic and diluted earnings per share                          1.56

4.      RATE AND OTHER REGULATORY MATTERS

       South Carolina Electric & Gas Company

        A. On July 20, 2000 the PSC issued an order  approving  SCE&G's  request
for an  out-of-period  adjustment  to increase the cost of gas  component of its
rates for natural gas service  from 54.334  cents per therm to 68.835  cents per
therm,  effective  with the first  billing  cycle in August 2000. As part of its
regularly  scheduled  annual  review of gas  costs,  the PSC  issued an order on
November 9, 2000 which  further  increased  the cost of gas  component to 78.151
cents per therm,  effective  with the first billing  cycle in November  2000. On
December 21, 2000 the PSC issued an order approving  SCE&G's request for another
out-of-period  adjustment  to increase the cost of gas component to 99.340 cents
per therm, effective with the first billing cycle in January 2001.

        B. On July 5, 2000 the PSC approved  SCE&G's  request to implement lower
depreciation  rates  for  its  gas  operations.  The new  rates  were  effective
retroactively  to  January  1,  2000  and  resulted  in a  reduction  in  annual
depreciation expense of approximately $2.9 million.

       C. On September 14, 1999 the PSC approved an accelerated capital recovery
plan for SCE&G's Cope Generating  Station.  The plan was  implemented  beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery  methodology  wherein  SCE&G  may  increase  depreciation  of its  Cope
Generating  Station  in excess of  amounts  that  would be  recorded  based upon
currently   approved   depreciation   rates.   The  amount  of  the  accelerated
depreciation  will be  determined  by SCE&G based on the level of  revenues  and
operating  expenses,  not to exceed $36 million annually without the approval of
the PSC. Any unused  portion of the $36 million in any given year may be carried
forward for  possible use in the  following  year.  As of December 31, 2000,  no
accelerated  depreciation  has been recorded.  The accelerated  capital recovery
plan will be accomplished through existing customer rates.

       D. On December 11, 1998 the PSC issued an order requiring SCE&G to reduce
retail electric rates on a prospective basis. The PSC acted in response to SCE&G
reporting  that it earned a 13.04 percent return on common equity for its retail
electric  operations for the 12 months ended  September 30, 1998. This return on
common  equity  exceeded  SCE&G's  authorized  return  of 12.0  percent  by 1.04
percent,  or $22.7  million,  primarily  as a result of record heat  experienced
during the summer.  The order  required  prospective  rate  reductions  on a per
kilowatt-hour  basis,  based on actual  retail  sales  for the 12  months  ended
September  30,  1998.  On January  12,  1999 the PSC denied  SCE&G's  motion for
reconsideration,  ruled that no further rate action was required, and reaffirmed
SCE&G's  authorized  return on equity of 12.0 percent.  The rate reductions were
placed into effect with the first billing cycle of January 1999.

        E. On January 9, 1996 the PSC issued an order granting SCE&G an increase
in retail  electric rates which were fully  implemented by January 1997. The PSC
authorized  a return on common  equity of 12.0  percent.  The PSC also  approved
establishment  of a Storm  Damage  Reserve  Account  capped at $50 million to be
collected through rates over a ten-year period.  Additionally,  the PSC approved
accelerated  recovery of a significant  portion of SCE&G's  electric  regulatory
assets  (excluding  deferred  income tax  assets) and the  remaining  transition
obligation  for  postretirement  benefits  other  than  pensions,  changing  the
amortization  periods to allow  recovery  by the end of the year  2000.  SCE&G's
request  to shift,  for  rate-making  purposes,  approximately  $257  million of
depreciation  reserves  from  transmission  and  distribution  assets to nuclear
production  assets  was also  approved.  The  Consumer  Advocate  and two  other
intervenors appealed certain issues in the order initially to the South Carolina
Circuit  Court  (Circuit  Court),  which  affirmed  the  PSC's  decisions,  and,
subsequently, to the South Carolina Supreme Court (Supreme Court). In March 1998
SCE&G, the PSC, the Consumer Advocate and one of the other  intervenors  reached
an  agreement  that  provided  for the  reversal  of the  shift in  depreciation
reserves  and the  dismissal  of the  appeal of all other  issues.  The PSC also
authorized SCE&G to adjust depreciation rates that had been approved in the 1996
rate order for its electric  transmission,  distribution and nuclear  production
properties  to eliminate  the effect of the  depreciation  reserve  shift and to
retroactively  apply such  depreciation  rates to February 1996. As a result,  a
one-time reduction in depreciation expense of $9.8 million was recorded in March
1998.  The  agreement  does  not  affect  retail  electric  rates.  The FERC had
previously  rejected the transfer of depreciation  reserves for rates subject to
its  jurisdiction.  In  September  1998 the Supreme  Court  affirmed the Circuit
Court's rulings on the issues contested by the remaining intervenor.

         F. In 1994 the PSC issued an order approving SCE&G's request to recover
through a billing  surcharge  to its gas  customers  the costs of  environmental
cleanup at the sites of former  manufactured  gas  plants  (MGPs).  The  billing
surcharge  is  subject  to  annual  review  and  provides  for the  recovery  of
substantially  all actual and projected  site  assessment  and cleanup costs and
environmental  claims settlements for SCE&G's gas operations that had previously
been  deferred.  In November  2000,  as a result of the annual  review,  the PSC
approved SCE&G's request to maintain the billing surcharge at $.011 per therm to
provide for the recovery of the remaining balance of $20.1 million.

        G. In September  1992 the PSC issued an order granting  SCE&G's  request
for a $.25  increase  in  transit  fares  from $.50 to $.75 in  Columbia,  South
Carolina; however, the PSC also required $.40 fares for low income customers and
denied SCE&G's  request to reduce the number of routes and frequency of service.
The new rates were placed into effect in October 1992.  SCE&G appealed the PSC's
order to the Circuit  Court,  which in May 1995 ordered the case back to the PSC
for  reconsideration  of several issues  including the low income rider program,
routing  changes,  and the $.75 fare.  The Supreme  Court  declined to review an
appeal of the Circuit Court  decision and dismissed the case.  The PSC and other
intervenors filed another Petition for Reconsideration,  which the Supreme Court
denied.  The PSC and other intervenors filed another appeal to the Circuit Court
which the Circuit Court denied in an order dated May 9, 1996. In this order, the
Circuit Court upheld its previous  orders and remanded  them to the PSC.  During
August  1996 the PSC heard  oral  arguments  on the  orders  on remand  from the
Circuit  Court.  On  September  30, 1996 the PSC issued an order  affirming  its
previous orders and denied SCE&G's request for  reconsideration.  In response to
an appeal of the PSC's order by SCE&G,  the Circuit Court issued an order on May
25, 2000,  which  remanded the matter to the PSC for review of SCE&G's  original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC  issued  an order  granting  the  relief  requested  by  SCE&G.  On
September 29, 2000 the Consumer  Advocate filed a motion with the PSC for a stay
of this  order to which  SCE&G  filed a  response.  On  October  3, 2000 the PSC
accepted  the  Consumer  Advocate's  motion and issued a stay of its order.  The
Consumer  Advocate and other  intervenors  have petitioned the Circuit Court for
judicial review of the PSC's order granting relief.  Action by the Circuit Court
is pending.

        Public Service Company of North Carolina, Incorporated

        H. On April  6,  2000 the NCUC  issued  an order  permanently  approving
PSNC's request to establish its commodity  cost of gas for large  commercial and
industrial  customers  on the basis of market  prices for natural  gas. The NCUC
previously  allowed PSNC use of this mechanism on a trial basis.  This procedure
allows PSNC to manage its deferred gas costs better by ensuring  that the amount
paid for natural gas to serve these customers  approximates the amount collected
from them.


        I. A state  expansion  fund,  established by the North Carolina  General
Assembly  in  1991  and  funded  by  refunds  from  PSNC's  interstate  pipeline
transporters,  provides  financing for expansion into areas that otherwise would
not be  economically  feasible  to serve.  On  December  30,  1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison,  Jackson and
Swain Counties,  North Carolina.  Pursuant to state statutes,  the NCUC required
PSNC to forfeit its exclusive  franchises to serve six counties in western North
Carolina  effective  January 31, 2000 because these  counties were not receiving
any natural gas service.  Madison,  Jackson and Swain  Counties were included in
the forfeiture  order.  On June 29, 2000 the NCUC approved  PSNC's  requests for
reinstatement  of its  exclusive  franchises  for  Madison,  Jackson  and  Swain
Counties and  disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million.


<PAGE>




        J.  On  December  7,  1999  the  NCUC  issued  an  order  approving  the
acquisition of PSNC by the Company. As specified in the NCUC order, PSNC reduced
its rates by  approximately $1 million in August 2000, will reduce rates another
$1 million in August  2001 and has agreed to a five-year  moratorium  on general
rate cases.  General  rate relief can be obtained  during this period to recover
costs associated with materially adverse  governmental actions and force majeure
events.

       K. On  February  22, 1999 the NCUC  approved  PSNC's  application  to use
expansion  funds to  extend  natural  gas  service  into  Alexander  County  and
authorized  disbursements from the fund of approximately $4.3 million based upon
budgeted  construction  cost of  approximately  $6.2 million.  Most of Alexander
County lies within PSNC's certificated  service territory and did not previously
have  natural gas  service.  The  project  was  completed  and  customers  began
receiving natural gas service in March 2000.

       L. On October 30, 1998 the NCUC  issued an order in PSNC's  general  rate
case filed in April 1998. The order,  effective  November 1, 1998,  granted PSNC
additional  revenue of $12.4 million and allowed a 9.82 percent  overall rate of
return on PSNC's net utility  investment.  It also approved the  continuation of
the Weather  Normalization  Adjustment  and Rider D  Mechanisms  and full margin
transportation  rates. PSNC's Rider D rate 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.  On February 4, 2000,  in
response to an appeal by the Carolina Utility Customers  Association,  Inc., the
Supreme Court of North Carolina affirmed the NCUC order.

5.      EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN

        Employee Benefit Plans

     The Company sponsors a noncontributory  defined benefit pension plan, which
covers substantially all permanent  employees.  The Company's policy has been to
fund the plan to the  extent  permitted  by the  applicable  Federal  income tax
regulations as determined by an independent actuary.

     Effective July 1, 2000 the Company's  pension plan was amended to provide a
cash balance formula. With certain exceptions,  employees were allowed to either
remain under the final  average pay formula or elect the cash  balance  formula.
Under the final  average pay formula,  benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment.  Under the cash balance formula,  the monthly benefit
earned  under the final  average pay formula at July 1, 2000 was  converted to a
lump sum amount for each  employee  and  increased  by  transition  credits  for
eligible  employees.  Under the cash balance  formula,  benefits based upon this
opening balance  increase going forward as a result of compensation  credits and
interest credits.  The effect of this plan amendment was to reduce the Company's
net  periodic   benefit   income  for  the  year  ended  December  31,  2000  by
approximately $3.7 million.

     In addition to pension  benefits,  the Company  provides  certain  unfunded
health  care and life  insurance  benefits  to  active  and  retired  employees.
Retirees  share in a portion of their  medical care cost.  The Company  provides
life insurance  benefits to retirees at no charge.  The costs of  postretirement
benefits other than pensions are accrued  during the years the employees  render
the services necessary to be eligible for the applicable benefits. Additionally,
to accelerate  the  amortization  of the  remaining  transition  obligation  for
postretirement  benefits  other than  pensions,  as  authorized  by the PSC, the
Company  expensed  approximately  $0.7  million and $15.7  million for the years
ended December 31, 1999 and 1998, respectively. (See Note 4E.)

     Effective July 1, 2000 PSNC's pension and postretirement benefit plans were
merged  with  SCANA's  plans.  At the time of the merger of the plans,  PSNC had
recorded  a  prepaid   pension  cost  of   approximately   $9.0  million  and  a
postretirement  welfare plan  obligation  of  approximately  $9.1 million in its
consolidated balance sheet.


<PAGE>




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>

Components of Net Periodic Benefit Cost

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

Millions of dollars                      2000          1999        1998          2000          1999        1998
                                         ----          ----        ----          ----          ----        ----

<S>                                   <C>          <C>          <C>             <C>           <C>          <C>
Service cost                          $ 8.3        $10.0        $ 8.3           $ 2.7         $ 3.0        $ 2.6
Interest cost                           33.5         27.9        25.9             10.2           9.5          9.4
Expected return on assets              (76.6)       (65.5)      (59.3)             n/a           n/a          n/a
Prior service cost amortization           3.0         1.1          1.1             0.8           0.7          0.7
Actuarial (gain) loss                  (12.2)        (8.6)        (9.6)               -          1.2          1.0
Transition amount amortization            0.8          0.8         0.8             0.8           1.7        19.1
                                                                                      -
Special termination benefit cost        -              5.5       -                               1.0        -
                                                 ----- ---       --          -             ----  ---        -
Net periodic benefit (income)
cost                                 $(43.2)      $(28.8)      $(32.8)          $14.5         $17.1        $32.8
                                     =======      ======       ======           =====         =====        =====

Weighted-Average Assumptions
                                            Retirement Benefits              Other Postretirement Benefits
                                   --------------------------------------    --------------------------------------

As of December 31,                     2000         1999        1998             2000          1999        1998
                                       ----         ----        ----             ----          ----        ----

Discount rate                          8.0%         8.0%        7.0%             8.0%          8.0%        7.0%
Expected return on plan assets         9.5%         9.5%        9.5%             n/a           n/a          n/a
Rate of compensation increase          4.0%         4.0%        4.0%             4.0%          4.0%        4.0%

Changes in Benefit Obligation

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

Millions of dollars                     2000           1999                  2000            1999
                                        ----           ----                  ----            ----

<S>                                    <C>            <C>                  <C>              <C>
Benefit obligation, January 1          $362.3         $389.3               $129.8           $137.0
Service cost                                8.3          10.0                   2.7              3.0
Interest cost                             33.5           27.9                 10.2               9.5
Plan participants' contributions            0.1            0.1                  0.5              0.5
Plan amendment                            65.4               -                  0.9                -
Actuarial (gain) loss                       1.6         (51.6)                 (7.8)          (14.5)
Acquisition/merger of plans               39.8               -                11.2                 -
Benefits paid                            (31.7)         (18.9)                 (8.5)            (6.7)

Special termination benefit cost              -            5.5               -                   1.0
                                     -----------   ------  ---               --        ------    ---
Benefit obligation, December 31        $479.3         $362.3               $139.0           $129.8
                                       ======         ======               ======           ======

Change in Plan Assets

                                                                     Retirement Benefits
                                                     ----------------------------------------------------
Millions of dollars                                            2000                      1999
                                                               ----                      ----

<S>                                                          <C>                        <C>
Fair value of plan assets, January 1                          $783.0                     $698.8
Actual return on plan assets                                    96.7                      103.0
Company contribution                                               -                          -
Plan participants' contributions                                 0.1                        0.1
Acquisition/merger of plans                                     46.2                          -
Benefits paid                                                  (31.7)                     (18.9)
                                                               -----                      -----
Fair value of  plan assets, December 31                       $894.3                     $783.0
                                                              ======                     ======




<PAGE>



Funded Status of Plans

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

Millions of dollars                                     2000        1999               2000               1999
                                                        ----        ----               ----               ----

<S>                                                   <C>         <C>              <C>             <C>
Funded status, December 31                             $415.0      $420.7           $(139.0)        $(129.8)
Unrecognized actuarial (gain) loss                      (297.6)     (294.0)             13.0            18.8
Unrecognized prior service cost                           73.7        11.4               4.5             4.3
Unrecognized net transition obligation                      4.8         5.6              8.3             9.1
                                                     ----------  ------ ---      -----   ---      -----  ---
Net amount recognized in Consolidated Balance Sheet    $195.9      $143.7           $(113.2)         $(97.6)
                                                     = ======      ======           ========         ======

Health Care Trends

The determination of net periodic other postretirement  benefit cost is based on
the following assumptions:

                                                                       2000       1999       1998
    ---------------------------------------------------------------- ---------- ---------- ----------

<S>                                                                    <C>        <C>        <C>
    Health care cost trend rate                                        7.5%       8.0%       8.5%
    Ultimate health care cost trend rate                               5.5%       5.5%       5.0%
    Year achieved                                                      2005       2005       2005
</TABLE>

      The effect of a  one-percentage-point  increase or decrease in the assumed
health care cost trend rates on the  aggregate of the service and interest  cost
components of net periodic other postretirement health care benefit cost and the
accumulated other postretirement benefit obligation for health care benefits are
as follows:

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

    Effect on health care cost                   $0.2              $(0.3)
    Effect on postretirement obligation           2.9               (3.4)

Long-Term Equity Compensation Plan

      The Long-Term Equity Compensation Plan (the Plan) became effective January
1, 2000.  The Plan  provides  for grants of  incentive  and  nonqualified  stock
options,  stock appreciation  rights,  restricted stock,  performance shares and
performance  units to certain key employees.  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. As of
December 31, 2000 only nonqualified stock options had been granted. One-third of
the options  vest on each  anniversary  of the date of grant until full  vesting
occurs in the third year.  The options expire ten years after the grant date. At
December 31, 2000, no stock options were  exercisable,  and none were  forfeited
during the year.

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

                                    Weighted
                                             Number of            Average
                                              Options         Exercise Price
                                          ----------------- --------------------
  Outstanding - December 31, 1999                      -                 -
  Granted                                     160,508             $25.53
                                          ================= ====================
  Outstanding - December 31, 2000             160,508             $25.53
                                          ================= ====================



<PAGE>




        The Company applies the intrinsic value method  prescribed by APB 25 and
related  interpretations  in accounting for grants made under the Plan.  Because
all options were granted with exercise  prices equal to the fair market value of
the Company's stock on the respective grant dates , no compensation  expense has
been  recognized in connection  with such grants.  If the Company had determined
compensation  expense for the issuance of options based on the fair value method
described in SFAS 123, "Accounting for Stock-Based Compensation," net income and
earnings  per share for 2000  would have been  reduced to the pro forma  amounts
presented below:


Net income - as reported  (millions)                               $250.4
Net income - pro forma (millions)                                   250.3
Basic earnings per share and diluted - as reported                   2.40
Basic earnings per share and diluted - pro forma                     2.40

        For purposes of the above pro forma  information,  the weighted  average
fair value at grant date (the value at grant date of the right to purchase stock
at a fixed price for an extended  time  period) for options  granted in 2000 was
$4.43 and was estimated  using the  Black-Scholes  Option pricing model with the
following weighted average assumptions.

Expected life of options (years)                          10
Risk free interest rate                                 5.99%
Volatility of underlying stock                            21%
Dividend yield of underlying stock                       4.4%

6.      LONG-TERM DEBT

        The  annual  amounts of  long-term  debt  maturities  and  sinking  fund
requirements for the years 2001 through 2005 are summarized as follows:

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

       2001              $41.0             2004              $186.3
       2002              887.3             2005               182.0
       2003              447.5
 ----------------- ----------------- ------------------ -----------------

        Approximately  $23.5 million of the portion of long-term debt payable in
2001 may be satisfied by either  deposit and  cancellation  of bonds issued upon
the basis of property  additions or bond  retirement  credits,  or by deposit of
cash with the Trustee.

        On August 7, 1996 the City of Charleston  executed  30-year electric and
gas franchise agreements with SCE&G. In consideration for the electric franchise
agreement, SCE&G is paying the City $25 million over seven years (1996-2002) and
has  donated to the City the  existing  transit  assets in  Charleston.  The $25
million is included in electric plant-in-service. In settlement of environmental
claims the City may have had against  SCE&G  involving  the  Calhoun  Park area,
where SCE&G and its predecessor companies operated a MGP until the 1960's, SCE&G
paid the City $26 million over a four-year period (1996-1999).

        SCE&G has three-year  revolving lines of credit totaling $75 million, in
addition  to other  lines of credit,  that  provide  liquidity  for  issuance of
commercial  paper. The three-year lines of credit provide back-up liquidity when
commercial paper outstanding is in excess of $175 million.  The long-term nature
of the lines of credit  allow  commercial  paper in excess of $175 million to be
classified as long-term  debt.  SCE&G's  commercial  paper  outstanding  totaled
$117.5  million and $143.1  million at December  31, 2000 and 1999,  at weighted
average interest rates of 6.59 percent and 6.63 percent, respectively.

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

     The Company has a $300 million credit agreement with banks. At December 31,
2000 the entire amount was outstanding.

7.     FUEL FINANCINGS

       Nuclear  and  fossil  fuel   inventories  and  sulfur  dioxide   emission
allowances  are  financed  through the  issuance by Fuel  Company of  short-term
commercial  paper.  These  short-term  borrowings  are  supported  by a  364-day
revolving credit agreement which expires December 19, 2001. 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.

       Commercial paper  outstanding  totaled $70.2 million at December 31, 2000
and 1999, at weighted  average  interest rates of 6.59 percent and 6.44 percent,
respectively.

8.     SHORT-TERM BORROWINGS

       The Company pays fees to banks as compensation for its committed lines of
credit.  Commercial paper borrowings are for 270 days or less.  Details of lines
of credit  (including  uncommitted  lines of credit) and short-term  borrowings,
excluding  amounts  classified  as long-term  (Note 6), at December 31, 2000 and
1999, are as follows:

Millions of dollars                                2000             1999
-------------------------------------------------------------- ---------------


Authorized lines of credit at year-end            $649.0              $558.3
Unused lines of credit at year-end                $564.0              $505.0
Short-term borrowings outstanding at year-end:
     Bank loans                                    $85.0               $53.2

          Weighted average interest rate            7.48%               7.80%
      Commercial paper                            $312.7              $213.3

          Weighted average interest rate            6.63%               6.63%

9.     COMMON EQUITY

     The changes in "Common  Stock,"  without par value,  during 2000,  1999 and
1998 are summarized as follows:

                                   Number of Shares    Millions of Dollars
-----------------------------------------------------------------------------
Balance at December 31, 1997          107,321,113               $1,152.9
   Repurchase of common stock          (3,748,490)                (110.0)
-----------------------------------------------------------------------------
Balance at December 31, 1998         103,572,623                 1,042.9
Changes in common stock                        -                  -
-----------------------------------------------------------------------------
Balance at December 31, 1999         103,572,623                 1,042.9

   Issuance of common stock           17,413,011                   487.7
   Repurchase of common stock        (16,256,503)                 (487.7)
-----------------------------------------------------------------------------

Balance at December 31, 2000          104,729,131               $1,042.9
=============================================================================

       The Restated  Articles of  Incorporation  of the Company do not limit the
dividends  that may be  payable  on its  common  stock.  However,  the  Restated
Articles of  Incorporation  of SCE&G and the Indenture  underlying its First and
Refunding Mortgage Bonds contain  provisions that, under certain  circumstances,
could limit the payment of cash dividends on its common stock. In addition, with
respect  to  hydroelectric   projects,   the  Federal  Power  Act  requires  the
appropriation of a portion of certain earnings  therefrom.  At December 31, 2000
approximately  $32.7  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 2000,  1999 and 1998
at an annual rate per share of $1.15, $1.32 and $1.54, respectively.

10.    PREFERRED STOCK

       The call premium of the respective  series of preferred  stock in no case
exceeds  the amount of the  annual  dividend.  Retirements  under  sinking  fund
requirements are at par values.  The aggregate annual amount of purchase fund or
sinking fund requirements for preferred stock for the years 2001 through 2005 is
$2.8 million.

       The  changes in "Total  Preferred  Stock  (Subject to purchase or sinking
funds)" during 2000, 1999 and 1998 are summarized as follows:

                                        Number of Shares   Millions of Dollars
--------------------------------------------------------- ----------------------
Balance at December 31, 1997                 251,094               $12.5
   Shares Redeemed  - $50 par value          (11,042)               (0.5)
--------------------------------------------------------- ----------------------
Balance at December 31, 1998                 240,052                12.0
   Shares Redeemed  - $50 par value           (8,565)               (0.4)
--------------------------------------------------------- ----------------------
Balance at December 31, 1999                 231,487                11.6
   Shares Redeemed - $50 par value           (11,200)               (0.6)
--------------------------------------------------------- ----------------------
Balance at December 31, 2000                 220,287                $11.0
========================================================= ======================

       On  October  28,  1997  SCE&G  Trust  I (the  "Trust"),  a  wholly  owned
subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55 percent Trust
Preferred Securities,  Series A (the "Preferred Securities").  SCE&G owns all of
the Common  Securities  of the Trust (the "Common  Securities").  The  Preferred
Securities  and  the  Common  Securities  (the  "Trust  Securities")   represent
undivided  beneficial  ownership interests in the assets of the Trust. The Trust
exists  for the sole  purpose  of  issuing  the Trust  Securities  and using the
proceeds  thereof to purchase  from SCE&G its 7.55 percent  Junior  Subordinated
Debentures  due September 30, 2027. The sole asset of the Trust is $50.0 million
of Junior Subordinated Debentures of SCE&G. Accordingly, no financial statements
of the Trust are presented.  SCE&G's  obligations under the Guarantee  Agreement
entered into in connection  with the Preferred  Securities,  when taken together
with  SCE&G's  obligation  to make  interest  and other  payments  on the Junior
Subordinated  Debentures  issued to the Trust and SCE&G's  obligations under the
Indenture  pursuant to which the Junior  Subordinated  Debentures  were  issued,
provides a full and unconditional  guarantee by SCE&G of the Trust's obligations
under the Preferred Securities.  Proceeds were used to redeem preferred stock of
SCE&G.

         The  preferred   securities  of  the  Trust  are  redeemable   only  in
conjunction with the redemption of the related 7.55 percent Junior  Subordinated
Debentures. The Junior Subordinated Debentures will mature on September 30, 2027
and may be redeemed,  in whole or in part, at any time on or after September 30,
2002 or upon the  occurrence of a Tax Event. A Tax Event occurs if an opinion is
received  from  counsel  experienced  in such matters that there is more than an
insubstantial  risk that:  (1) the Trust is or will be subject to Federal income
tax,  with  respect to income  received  or  accrued on the Junior  Subordinated
Debentures,  (2) interest payable by SCE&G on the Junior Subordinated Debentures
will not be  deductible,  in whole or in part,  by SCE&G for Federal  income tax
purposes,  or (3) the Trust will be subject to more than a de minimis  amount of
other taxes, duties, or other governmental charges.

         Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously  be applied to redeem  Preferred  Securities  having an aggregate
liquidation  amount  equal  to the  aggregate  principal  amount  of the  Junior
Subordinated  Debentures.  The Preferred  Securities  are  redeemable at $25 per
preferred security plus accrued distributions.


<PAGE>




11.    INCOME TAXES

       Total income tax expense  attributable to income before cumulative effect
of accounting change for 2000, 1999 and 1998 is as follows:

Millions of dollars                              2000         1999         1998
----------------------------------------------------------------------- --------
Current taxes:
      Federal                                    $88.2        $94.5      $114.8
      State                                        9.2          0.6         2.2
----------------------------------------------------------------------- --------
----------------------------------------------------------------------- --------
            Total current taxes                   97.4         95.1       117.0
----------------------------------------------------------------------- --------
----------------------------------------------------------------------- --------
Deferred taxes, net:
      Federal                                     29.8          6.1         2.3
      State                                        4.7          1.5         2.0
----------------------------------------------------------------------- --------
----------------------------------------------------------------------- --------
            Total deferred taxes                  34.5          7.6         4.3
----------------------------------------------------------------------- --------
----------------------------------------------------------------------- --------
Investment tax credits:
      Deferred - State                             5.0         13.4        14.3
      Amortization of amounts deferred - State    (1.3)        (1.2)       (0.9)
      Amortization of amounts deferred - Federal  (4.0)        (3.6)       (3.6)
----------------------------------------------------------------------- --------
            Total investment tax credits          (0.3)         8.6         9.8
----------------------------------------------------------------------- --------
Non-conventional fuel tax credits:
      Deferred - Federal                           9.4          n/a         n/a
----------------------------------------------------------------------- --------
            Total income tax expense            $141.0       $111.3      $131.1
======================================================================= ========

       The  difference   between  actual  income  tax  expense  and  the  amount
calculated  from the  application of the statutory  Federal income tax rate (35%
for  2000,  1999  and  1998) to  pre-tax  income  before  cumulative  effect  of
accounting change is reconciled as follows: <TABLE>

Millions of dollars                                                   2000              1999             1998
--------------------------------------------------------------- ----------------- ----------------- -----------------

<S>                                                                  <C>               <C>               <C>
Income before cumulative effect of accounting change                 $221.6            $179.0            $223.4
Total income tax expense:
   Charged to operating expense                                        152.0            112.9              136.2
   Credited to other items                                              (11.0)            (1.6)               (5.1)
Preferred stock dividends                                                 7.4              7.4                 7.5
--------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
      Total pre-tax income                                           $370.0            $297.7            $362.0
=============================================================== ================= ================= =================
=============================================================== ================= ================= =================

Income taxes on above at statutory Federal income tax rate           $129.5            $104.2            $126.7
Increases (decreases) attributed to:
   State income taxes (less Federal income tax effect)                  11.4               9.3            11.4
    Non-deductible book amortization of acquisition
adjustments                                                               5.0              0.4             0.4
   Amortization of Federal investment tax credits                        (4.0)            (3.6)               (3.6)
   Other differences, net                                                (0.9)             1.0                (3.8)
--------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
        Total income tax expense                                     $141.0            $111.3            $131.1
=============================================================== ================= ================= =================

</TABLE>


<PAGE>





       The tax  effects of  significant  temporary  differences  comprising  the
Company's net deferred tax liability of $819.2  million at December 31, 2000 and
$789.2 million at December 31, 1999 (see Note 1I), are as follows:

Millions of dollars                                2000                1999
--------------------------------------------- ---------------- -----------------
Deferred tax assets:

   Unamortized investment tax credits               $63.0              $62.8
   Other postretirement benefits                     40.6               36.6
   Early retirement programs                         14.6               14.8
   Deferred compensation                              8.8                8.8
   Cycle billing                                        -               15.5
   Other                                             27.4               19.0
--------------------------------------------- ---------------- -----------------
        Total deferred tax assets                   154.4              157.5
--------------------------------------------- ---------------- -----------------

Deferred tax liabilities:
   Property, plant and equipment                    765.5              665.4
   Investments in equity securities                  80.0              184.7
   Pension  plan benefit income                      65.3               50.7
   Research and experimentation costs                26.8               27.3
   Deferred fuel costs                               18.5                5.5
   Cycle billing                                      1.9                  -
   Other                                             15.6               13.1
--------------------------------------------- ---------------- -----------------
        Total deferred tax liabilities              973.6              946.7
--------------------------------------------- ---------------- -----------------
Net deferred tax liability                         $819.2             $789.2
============================================= ================ =================


       The Internal Revenue Service has examined and closed consolidated Federal
income tax  returns of the Company  through  1995,  has  examined  and  proposed
adjustments  to the Company's  1996 and 1997 Federal  returns,  and is currently
examining the Company's  Federal returns for 1998 and 1999. The Company does not
anticipate that any adjustments which might result from these  examinations will
have a significant impact on its results of operations,  cash flows or financial
position.

12.    FINANCIAL INSTRUMENTS

     The carrying  amounts and estimated fair values of the Company's  financial
instruments at December 31, 2000 and 1999 are as follows:
<TABLE>

Millions of dollars                                                   2000                          1999
--------------------------------------------------------- ----------------------------- -----------------------------
                                                                           Estimated                     Estimated
                                                            Carrying         Fair         Carrying         Fair
                                                             Amount          Value         Amount          Value
--------------------------------------------------------- -------------- -------------- -------------- --------------
Assets:
<S>                                                            <C>           <C>             <C>            <C>
    Cash and temporary cash investments                        $158.7        $158.7          $116.0         $116.0
    Investments                                                 681.7       1,234.5            941.8       1,952.4
Liabilities:
    Short-term borrowings                                       397.7          397.7           266.5          266.5
    Long-term debt                                           2,890.5        2,931.9         1,865.8        1,830.7
    Preferred stock (subject to purchase or sinking
funds)                                                           11.0             8.7            11.6  8.5

</TABLE>
       The  information   presented  herein  is  based  on  pertinent  available
information as of December 31, 2000 and 1999.  Although the Company is not aware
of any factors that would significantly affect the estimated fair value amounts,
such financial instruments have not been comprehensively revalued since December
31, 2000, and the current estimated fair value may differ significantly from the
estimated fair value at that date.


<PAGE>



       The  following  methods and  assumptions  were used to estimate  the fair
value of the above classes of financial instruments:

o              Cash and temporary cash investments,  including commercial paper,
               repurchase  agreements,  treasury bills and notes,  are valued at
               their carrying amount.

o              Fair values of investments and long-term debt are based on quoted
               market prices of the instruments or similar instruments. For debt
               instruments   for  which  there  are  no  quoted   market  prices
               available,   fair   values  are  based  on  net   present   value
               calculations.  For  investments  for which the fair  value is not
               readily determinable, fair value approximates cost. 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.

At December 31, 2000, SCANA Communications Holdings, Inc. (SCH), a wholly owned,
indirect  subsidiary  of SCANA,  held the following  investments  in ITC Holding
Company, Inc. (ITC) and its affiliates:

          o    Powertel,  Inc. (Powertel) is a publicly traded company that owns
               and operates  personal  communications  services (PCS) systems in
               several major  Southeastern  markets.  SCH owns approximately 4.9
               million  common  shares of  Powertel  at a cost of  approximately
               $77.7 million. Powertel common stock closed at $61.9375 per share
               on December 31, 2000,  resulting in a pre-tax  unrealized holding
               gain of $228.8 million (a decline of $189.0 million from December
               31, 1999).  Accumulated other  comprehensive  income includes the
               after-tax  amount of all  unrealized  holding gains and losses on
               common  shares.  In addition,  SCH owns the  following  series of
               non-voting  convertible preferred shares, at the approximate cost
               noted:  100,000  shares series B ($75.1  million);  50,000 shares
               series D ($22.5 million);  and 50,000 shares 6.5 percent series E
               ($75.0  million).  Cumulative  dividends  on  preferred  series E
               shares are  generally  paid in common  shares of Powertel and are
               accrued  quarterly.  Preferred series B shares become convertible
               in March 2002 at a conversion price of $16.50 per common share or
               approximately  4.6  million  common  shares.  Preferred  series D
               shares become  convertible in March 2002 at a conversion price of
               $12.75 per  common  share or  approximately  1.7  million  common
               shares. Preferred series E shares become convertible in June 2003
               at a conversion price of $22.01 per common share or approximately
               3.4 million  common shares.  The market value of the  convertible
               preferred  shares  of  Powertel  is  not  readily   determinable.
               However, as converted,  the market value of the underlying common
               shares for the preferred shares was approximately  $606.9 million
               at December 31, 2000,  reflecting an unrecorded  pre-tax  holding
               gain of $434.3 million (a decline of $368.4 million from December
               31, 1999).

               On August 28,  2000 SCH  announced  that under  terms of separate
               definitive  agreements,  Powertel  has agreed to be  acquired  by
               either Deutsche  Telekom AG or VoiceStream  Wireless  Corporation
               (VoiceStream).   If  Deutsche  Telekom's   previously   announced
               acquisition  of  VoiceStream  is  successfully  completed,   then
               Deutsche  Telekom  would also acquire  Powertel.  If the Deutsche
               Telekom  -  VoiceStream   transaction  is  not  completed,   then
               VoiceStream  would acquire  Powertel.  In  connection  with these
               transactions,  SCH entered into stockholder  agreements with each
               of Deutsche Telekom and VoiceStream  pursuant to which SCH agreed
               to vote  its  Powertel  shares  in  support  of  either  of these
               transactions.  In addition, SCH agreed to certain restrictions on
               disposition  of its  Powertel  shares  and the  shares  it  would
               receive  in  either  of these  transactions.  On March  13,  2001
               Powertel shareholders approved the acquisition agreements.


<PAGE>




          o    ITC^DeltaCom,  Inc.  (ITCD) is a fiber  optic  telecommunications
               provider.  SCH owns  approximately  5.1 million  common shares of
               ITCD at a cost of approximately $43.0 million.  ITCD common stock
               closed at $5.39 per share on December 31,  2000,  resulting in an
               unrealized  pre-tax  holding loss of $15.4  million (a decline of
               $113.7  million  from  December  31,  1999).   Accumulated  other
               comprehensive   income  includes  the  after-tax  amount  of  all
               unrealized   holding  gains  and  losses  on  common  shares.  In
               addition,  SCH owns 1,480,771  shares of series A preferred stock
               of  ITCD at a cost  of  approximately  $11.2  million.  Series  A
               preferred shares become  convertible in March 2002 into 2,961,542
               shares  of ITCD  common  stock.  The  market  value  of  series A
               preferred stock of ITCD is not readily determinable.  However, as
               converted,  the market value of the  underlying  common stock for
               the series A preferred stock was  approximately  $16.0 million at
               December 31, 2000,  reflecting an unrecorded pre-tax holding gain
               of $4.8  million (a decline of $65.8  million  from  December 31,
               1999).

          o    Knology, Inc. (Knology) is a broad-band service provider of cable
               television, telephone and internet services. SCH owns $71,050,000
               face amount of 11.875 percent  Senior  Discount Notes due 2007 of
               Knology  Broadband,  Inc., a wholly-owned  subsidiary of Knology.
               The Senior  Discount Notes have a book basis at December 31, 2000
               of   approximately   $57.9   million.   In  addition,   SCH  owns
               approximately  7.2 million shares of Knology Series A Convertible
               Preferred Stock with a cost basis of  approximately  $5.0 million
               and  warrants to  purchase  approximately  0.2 million  shares of
               Series A  Convertible  Preferred  Stock.  On January 12, 2001 SCH
               invested  $25.0 million for  approximately  8.3 million shares of
               Series C Convertible Preferred Stock of Knology. The market value
               of these investments is not readily determinable.

o             ITC   holds   ownership   interests   in   several    Southeastern
              communications  companies,  including those discussed  above.  SCH
              owns  approximately  3.1 million common  shares,  645,153 series A
              convertible  preferred  shares,  and 133,664  series B convertible
              preferred shares of ITC. These investments cost approximately $5.8
              million, $7.2 million, and $4.0 million,  respectively. The market
              values of these investments are not readily determinable.

13.    COMMITMENTS AND CONTINGENCIES

A.      Lake Murray Dam Reinforcement

        On October 15, 1999 FERC notified  SCE&G of its  agreement  with SCE&G's
plan to  reinforce  Lake Murray Dam in order to maintain  the lake in case of an
extreme earthquake.  SCE&G and FERC have been discussing possible  reinforcement
alternatives  for the dam over the past several years as part of SCE&G's ongoing
hydroelectric  operating license with FERC. Until discussions are concluded,  it
is not  possible to finalize the cost of the  project;  however,  it is possible
that the cost could range up to $250  million.  Although  any costs  incurred by
SCE&G are  expected to be  recoverable  through  electric  rates,  SCE&G also is
exploring  alternative  sources  of  funding.  The  project  is  expected  to be
completed in 2004.

B.     Nuclear Insurance

       The Price-Anderson Indemnification Act, which deals with public liability
for  a  nuclear  incident,   currently   establishes  the  liability  limit  for
third-party  claims  associated with any nuclear incident at $9.5 billion.  Each
reactor  licensee is currently  liable for up to $88.1 million per reactor owned
for each  nuclear  incident  occurring  at any  reactor  in the  United  States,
provided  that not more than $10 million of the  liability  per reactor would be
assessed per year. SCE&G's maximum assessment, based on its two-thirds ownership
of Summer Station,  would be approximately  $58.7 million per incident,  but not
more than $6.7 million per year.

       SCE&G  currently  maintains  policies (for itself and on behalf of Santee
Cooper) with Nuclear Electric  Insurance  Limited (NEIL).  The policies covering
the nuclear facility for property damage, excess property damage and outage cost
permit assessments under certain conditions to cover insurer's losses.  Based on
the  current  annual  premium,  SCE&G's  portion  of the  retrospective  premium
assessment would not exceed $8.1 million.

       To the extent that insurable claims for property damage, decontamination,
repair and  replacement  and other  costs and  expenses  arising  from a nuclear
incident at Summer  Station  exceed the policy  limits of  insurance,  or to the
extent such insurance becomes  unavailable in the future, and to the extent that
SCE&G's  rates would not recover the cost of any  purchased  replacement  power,
SCE&G  will  retain the risk of loss as a  self-insurer.  SCE&G has no reason to
anticipate a serious  nuclear  incident at Summer  Station.  If such an incident
were to occur, it could have a material adverse impact on the Company's  results
of operations, cash flows and financial position.

C.     Environmental

       South Carolina Electric & Gas Company

       In September  1992 the  Environmental  Protection  Agency (EPA)  notified
SCE&G,  the City of Charleston  and the  Charleston  Housing  Authority of their
potential  liability for the  investigation and cleanup of the Calhoun Park area
site in Charleston, South Carolina. This site encompasses approximately 30 acres
and  includes  properties  which  were  locations  for  industrial   operations,
including a wood  preserving  (creosote)  plant,  one of SCE&G's  decommissioned
MGPs,  properties owned by the National Park Service and the City of Charleston,
and private properties.  The site has not been placed on the National Priorities
List, but may be added in the future. The Potentially Responsible Parties (PRPs)
negotiated  an  administrative  order by consent  for the  conduct of a Remedial
Investigation/Feasibility  Study and a corresponding  Scope of Work.  Field work
began in November 1993, and the EPA approved a Remedial  Investigation Report in
February 1997 and a Feasibility  Study Report in June 1998. In July 1998 the EPA
approved SCE&G's Removal Action Work Plan for soil  excavation.  SCE&G completed
Phase One of the  Removal  Action  Work Plan in 1998 at a cost of  approximately
$1.5  million.  Phase  Two,  which cost  approximately  $3.5  million,  included
excavation and installation of several  permanent  barriers to mitigate coal tar
seepage.  On September 30, 1998 a Record of Decision was issued which sets forth
the EPA's view of the extent of each PRP's responsibility for site contamination
and the level to which the site must be  remediated.  SCE&G  estimates  that the
Record of Decision will result in costs of approximately $13.3 million, of which
approximately  $2  million  remains.  On  January  13,  1999  the EPA  issued  a
Unilateral   Administrative  Order  for  Remedial  Design  and  Remedial  Action
directing  SCE&G to design and carry out a plan of  remediation  for the Calhoun
Park site.  SCE&G submitted a Comprehensive  Remedial Design Work Plan (RDWP) on
December 17, 1999 and proceeded with implementation pending agency approval. The
RDWP was approved by the EPA in July 2000, and its implementation continues.

       In  October  1996  the  City  of   Charleston   and  SCE&G   settled  all
environmental  claims the City may have had against SCE&G  involving the Calhoun
Park area for a payment of $26 million over four years  (1996-1999)  by SCE&G to
the City.  SCE&G is  recovering  the  amount of the  settlement,  which does not
encompass site assessment and cleanup costs, through rates in the same manner as
other amounts accrued for site  assessments  and cleanup as discussed  above. As
part of the environmental  settlement,  SCE&G constructed an 1,100 space parking
garage on the Calhoun Park site  (construction  was completed in April 2000) and
transferred  the facility to the City in exchange for a $16.5  million,  18-year
municipal bond  collateralized  by revenues from, and a mortgage on, the parking
garage.

        SCE&G owns three other  decommissioned  MGP sites which contain residues
of  by-product  chemicals.  For the site  located  in  Sumter,  South  Carolina,
effective September 15, 1998, SCE&G entered into a Remedial Action Plan Contract
with DHEC pursuant to which it agreed to undertake a full site investigation and
remediation under the oversight of DHEC. Site investigation and characterization
are   proceeding   according  to  schedule.   Upon   selection  and   successful
implementation  of a  site  remedy,  DHEC  will  give  SCE&G  a  Certificate  of
Completion,  and a covenant not to sue. For the site located in Florence,  South
Carolina,  SCE&G entered into a similar  Remedial Action Plan Contract with DHEC
effective  September 5, 2000.  SCE&G is continuing to investigate  the remaining
site  in  Columbia,  and  is  monitoring  the  nature  and  extent  of  residual
contamination.

       Public Service Company of North Carolina, Incorporated

       PSNC owns, or has owned, all or portions of seven sites in North Carolina
on  which  MGPs  were  formerly  operated.  Intrusive  investigation  (including
drilling,  sampling and analysis) has begun at only one site,  and the remaining
sites have been evaluated using  historical  records and observations of current
site conditions.  These evaluations have revealed that MGP residuals are present
or  suspected  at  several  of the  sites.  The  North  Carolina  Department  of
Environment  and Natural  Resources has  recommended  that no further  action be
taken with respect to one site. An  environmental  due diligence  review of PSNC
conducted in February  1999  estimated  that the cost to remediate the remaining
sites would range  between $11.3  million and $21.9  million.  During the second
quarter of 2000,  the review  was  finalized  and the  estimated  liability  was
recorded.  PSNC is unable to  determine  the rate at which costs may be incurred
over this time  period.  The  estimated  cost range has not been  discounted  to
present value.  PSNC's  associated actual costs for these sites will depend on a
number of  factors,  such as actual  site  conditions,  third-party  claims  and
recoveries  from other PRPs. An order of the NCUC dated May 11, 1993  authorized
deferral  accounting  for  all  costs  associated  with  the  investigation  and
remediation of MGP sites. As of December 31, 2000, PSNC has recorded a liability
and associated  regulatory  asset of $10.2  million,  which reflects the minimum
amount of the  range,  net of shared  cost  recovery  from other  PRPs.  Amounts
incurred to date are not  material.  Management  intends to request  recovery of
additional  MGP cleanup costs not recovered  from other PRPs in future rate case
filings, and believes that all costs incurred will be recoverable in gas rates.

D.     Franchise Agreement

       See Note 6 for a discussion of the electric  franchise  agreement between
SCE&G and the City of Charleston.

E.     Claims and Litigation

       The Company and  Westvaco  each own a 50 percent  interest in Cogen South
LLC (Cogen).  Cogen was formed to build and operate a  cogeneration  facility at
Westvaco's Kraft Division Paper Mill in North  Charleston,  South Carolina.  The
facility began operations in March 1999. On September 10, 1998 the contractor in
charge of  construction  filed suit in Circuit Court seeking  approximately  $52
million  from  Cogen,  alleging  that it  incurred  construction  cost  overruns
relating  to the  facility  and  that the  construction  contract  provides  for
recovery of these costs. In addition to Cogen,  Westvaco,  SCE&G and the Company
were also named as defendants in the suit. The Company and the other  defendants
believe the suit is without merit and are mounting an appropriate  defense.  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.

       On  December  2, 1999 an  unsuccessful  bidder  for the  purchase  of the
propane gas assets of SCANA filed suit against  SCANA in Circuit  Court  seeking
unspecified  damages.  The suit alleges the existence of a contract for the sale
of assets to the plaintiff  and various  causes of action  associated  with that
contract.  The Company is confident  in its  position and intends to  vigorously
defend the lawsuit.  The Company does not believe  that the  resolution  of this
issue will have a material  impact on its results of  operations,  cash flows or
financial position.

       The  Company  is also  engaged  in various  other  claims and  litigation
incidental  to its business  operations  which  management  anticipates  will be
resolved without material loss to the Company.

14.    SEGMENT OF BUSINESS INFORMATION

       The  Company's  reportable  segments,  based on  combined  revenues  from
external and internal sources,  are Electric Operations,  Gas Distribution,  Gas
Transmission, Retail Gas Marketing and Energy Marketing. 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 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 PSC.  SCE&G is also
regulated  by FERC.  GENCO owns and operates  the  Williams  Station  generating
facility and sells all of its electric  generation to SCE&G.  GENCO is regulated
by FERC.  Fuel Company  acquires,  owns and provides  financing for the fuel and
emission  allowances  required for the  operation of SCE&G and GENCO  generation
facilities.

       Gas Distribution, comprised of the local distribution operations of SCE&G
and PSNC, is engaged in the purchase and sale,  primarily at retail,  of natural
gas.  SCE&G's  operations  extend  to 31  counties  in South  Carolina  covering
approximately  21,000 square miles.  PSNC was acquired by SCANA in 2000.  PSNC's
operations cover 25 counties in North Carolina and  approximately  11,500 square
miles. Gas Transmission is comprised of Pipeline  Corporation,  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.  Pipeline  Corporation also owns LNG
liquefaction and storage facilities. Both of these segments are regulated by the
state commission in their respective state of operations.

       Retail Gas Marketing markets natural gas in Georgia's deregulated natural
gas market.  Energy Marketing markets  electricity,  natural gas and other light
hydrocarbons, primarily in the Southeast.

       The Company's  regulated  reportable  segments share a similar regulatory
environment and, in some cases,  overlapping  service areas.  However,  Electric
Operations'  product  differs from the other  segments,  as does its  generation
process  and method of  distribution.  The gas  segments  differ from each other
primarily  based  on the  class  of  customers  each  serves  and the  marketing
strategies  resulting  from  those  differences.   The  marketing  segments  are
non-regulated,  but differ from each other primarily  based on their  respective
markets.

Disclosure of Reportable Segments
<TABLE>

Millions of dollars
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
                       Electric       Gas           Gas       Retail Gas    Energy        All     Adjustments/   Consolidated
        2000          Operations  Distribution Transmission   Marketing    Marketing     Other    Eliminations      Total
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------

External Customer
<S>                     <C>           <C>          <C>           <C>         <C>          <C>         <C>           <C>
Revenue                 $1,344        $745         $253          $548        $544         $41         $(42)         $3,433
Intersegment Revenue        318           1          236             -            -          9       (564)                -
Operating Income
(Loss)                     446           85           28           n/a         n/a           -           (5)           554
Interest Expense             13          20            4             5            1         26         156             225
Depreciation &
Amortization               155           53            7             1            -          5          (4)            217
Income Tax Expense
(Benefit)                     1          23            8             1           (1)        (4)        113             141
Net Income (loss)             7          19           16            4           (4)         (6)       214              250
Segment Assets          4,953        1,628          309          103          215         685        (473)           7,420
Expenditures for
Assets                     229          58           18             -            -           8          48             361
Deferred Tax Assets          6            -            3            5            4           1         (19)               -
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------

Millions of dollars
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
                       Electric       Gas           Gas       Retail Gas    Energy        All     Adjustments/   Consolidated
        1999          Operations  Distribution Transmission   Marketing    Marketing     Other    Eliminations      Total
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------

External Customer
<S>                     <C>          <C>           <C>           <C>         <C>          <C>         <C>           <C>
Revenue                 $1,226       $234          $188          $207        $224         $73         $(74)         $2,078
Intersegment Revenue       308            5         154              -            -        11         (478)               -
Operating Income
(Loss)                     390          22            20          n/a          n/a                     (79)            353
Interest Expense             12        n/a             4            4             1        23           98             142
Depreciation &
Amortization               148          13             7             1            1          7           (8)           169
Income Tax Expense
(Benefit)                     1        n/a             9          (24)           (2)       21          106             111
Net Income (loss)             6        n/a           14           (45)           (4)       22          186             179
Segment Assets           4,751        399           253           (24)         168        932        (468)           6,011
Expenditures for
Assets                     201          19             8            2             1          6          24             261
Deferred Tax Assets           6        n/a             3            -             1          1            5             16
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------


Millions of dollars
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
                       Electric       Gas           Gas       Retail Gas    Energy        All     Adjustments/   Consolidated
        1998          Operations  Distribution Transmission   Marketing    Marketing     Other    Eliminations      Total
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------

External Customer
Revenue                 $1,220       $225          $185           $3         $565         $68        $(160)         $2,106
Intersegment Revenue       286            5          145           -              -          8        (444)               -
Operating Income
(Loss)                     436          29            27         n/a           n/a           -          (22)           470
Interest Expense             11        n/a             4          -              -          19           89            123
Depreciation &
Amortization               126          12             7          -              -           7           (7)           145
Income Tax Expense
(Benefit)                     -        n/a             8         (4)            (3)         (2)         132            131
Net Income (loss)             6        n/a           16          (8)            (7)         (4)         220            223
Segment Assets           4,600        381           239           2             71        503          (515)         5,281
Expenditures for
Assets                      205        19            11           2              2         17            47            303
Deferred Tax Assets           5       n/a              3          -              -           4           10              22
--------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------

</TABLE>

       Revenues and assets from segments below the  quantitative  thresholds are
attributable to SCE&G's transit operations,  which are regulated by the PSC, and
to nine other  wholly owned  subsidiaries  of the  Company.  These  subsidiaries
conduct  non-regulated   operations  in  energy-related  and  telecommunications
industries.  None of these  subsidiaries met any of the quantitative  thresholds
for determining reportable segments in 2000, 1999 or 1998.

       Management  uses operating  income to measure segment  profitability  for
regulated operations.  For non-regulated operations,  management uses net income
for this  purpose.  Accordingly,  SCE&G does not  allocate  interest  charges or
income tax expense  (benefit) to the  Electric  Operations  or Gas  Distribution
segments.   Similarly,   management   evaluates   utility   plant  for  segments
attributable  to SCE&G and  total  assets  for SCE&G as a whole,  as well as for
other  operating  segments.  Therefore,  SCE&G  does  not  allocate  accumulated
depreciation, common and non-utility plant, or deferred tax assets to reportable
segments.  However,  GENCO and PSNC do have interest  charges,  income taxes and
deferred  tax  assets,  which  are  included  in  Electric  Operations  and  Gas
Distribution,  respectively.  Interest  income is not reported by segment and is
not material. For 2000, adjustments to net income and income tax expense include
the effect of the accounting change described in Note 2.

       The Consolidated Financial Statements report operating revenues which are
comprised of the reportable segments.  Revenues from non-reportable segments are
included in Other Income.  Therefore,  the  adjustments  to total revenue remove
revenues from  non-reportable  segments.  Adjustments  to Net Income  consist of
SCE&G's unallocated net income.

       Adjustments  to assets  consist  of  various  reclassifications  made for
external  reporting   purposes.   Segment  assets  include  utility  plant  only
(excluding accumulated  depreciation) for Electric Operations,  Gas Distribution
and Transit  Operations,  and all assets for Gas  Transmission and the remaining
non-reportable  segments.  As a result,  unallocated assets include  accumulated
depreciation,  offset in part by common, non-utility and non-regulated plant for
SCANA  and  SCE&G,  and  by  non-fixed  assets  for  Electric  Operations,   Gas
Distribution and Transit Operations.

       Adjustments  to  Interest  Expense,  Income  Tax  Expense  (Benefit)  and
Deferred Tax Assets  include  primarily  the totals from SCANA or SCE&G that are
not  allocated to the segments.  Interest  Expense is also adjusted to eliminate
inter-affiliate charges. Adjustments to depreciation and amortization consist of
non-reportable segment expenses,  which are not included in the depreciation and
amortization  reported on a  consolidated  basis.  Deferred  Tax Assets are also
adjusted to remove the non-current portion of those assets.

15.      SUBSEQUENT EVENTS

       On January 24, 2001 SCANA  issued $202  million  two-year  floating  rate
notes maturing on January 24, 2003. The interest rate is reset  quarterly  based
on  three-month  LIBOR plus 110 basis  points.  Also on January  24,  2001 SCE&G
issued $150 million First Mortgage Bonds having an annual  interest rate of 6.70
percent and maturing on February 1, 2011.  On February 16, 2001 PSNC issued $150
million of medium-term notes having an annual interest rate of 6.625 percent and
maturing on February 15, 2011. The proceeds from these  borrowings  were used to
reduce short-term debt and for general corporate purposes.



<PAGE>



16.  QUARTERLY FINANCIAL DATA (UNAUDITED)

(Millions of dollars, except per share amounts)

<TABLE>

---------------------------------------------------------------------------------------------------------------------------
                                                     First        Second        Third         Fourth
2000                                                Quarter       Quarter      Quarter        Quarter       Annual
------------------------------------------------- ------------- ------------ ------------- -------------- -----------

<S>                                                   <C>           <C>           <C>         <C>           <C>
Total operating revenues                              $821          $662          $816        $1,134        $3,433
Operating income                                       172(1)          99          146            137          554
Income before cumulative effect of
  accounting change                                     75             28          59             59           221
Cumulative effect of accounting change,
   net of taxes                                         29              -             -            -           29
Net income                                            104             28            59            59          250
Basic and diluted earnings per share
  before cumulative effect
  of accounting change                                 .72           .27           .56           .57         2.12
Cumulative effect of accounting change,
  net of taxes                                         .28              -             -             -          .28
Basic and diluted earnings per share                  1.00            .27          .56           .57         2.40


---------------------------------------------------------------------------------------------------------------------------
                                                     First         Second        Third        Fourth
1999                                                Quarter        Quarter      Quarter       Quarter       Annual
------------------------------------------------- ------------- -------------- ----------- -------------- -----------
                                                           (Millions of Dollars, except per share amounts)

<S>                                                   <C>           <C>             <C>         <C>       <C>
Total operating revenues                              $546          $435            $558        $539      $2,078

Operating income                                         88            69      135                  61         353

Net income                                               37            24      67                   51         179

Basic and diluted earnings per share                    .36           .23      .65                 .49        1.73
------------------------------------------------- ------------- -------------- ----------- -------------- -----------
</TABLE>

(1) Excludes $52 million of income  taxes that were  formerly  reported in first
quarter operating income.

<PAGE>






















                      SOUTH CAROLINA ELECTRIC & GAS COMPANY












Item 7.       Management's Discussion and Analysis of Financial Condition
                  and Results of Operations..............................  74

Item 7A.      Quantitative Disclosures About Market Risk.................  84

Item 8.       Financial Statements and Supplementary Data................  84


<PAGE>



ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS

       Statements included in this discussion and analysis (or elsewhere in this
annual report) which are not  statements of historical  fact are intended to be,
and are hereby identified as,  "forward-looking  statements" for purposes of the
safe harbor  provided by Section 27A of the  Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended.  Readers are
cautioned that any such forward-looking  statements are not guarantees of future
performance  and  involve a number of risks and  uncertainties,  and that actual
results could differ  materially  from those  indicated by such  forward-looking
statements.  Important  factors  that  could  cause  actual  results  to  differ
materially from those indicated by such forward-looking  statements include, but
are not limited to, the following:  (1) that the information is of a preliminary
nature and may be subject to further and/or  continuing  review and  adjustment,
(2) changes in the utility regulatory  environment,  (3) changes in the economy,
especially in SCE&G's  service  territory,  (4) the impact of  competition  from
other energy suppliers,  (5) growth opportunities,  (6) the results of financing
efforts,  (7) changes in SCE&G's accounting  policies,  (8) weather  conditions,
especially  in  areas  served  by  SCE&G,   (9)   inflation,   (10)  changes  in
environmental  regulations and (11) the other risks and uncertainties  described
from  time to time in  SCE&G's  periodic  reports  filed  with  the  SEC.  SCE&G
disclaims any obligation to update any forward-looking statements.

COMPETITION

Regulated Electric and Gas Markets

        Efforts to restructure  electric  markets at the state level have slowed
considerably.  Dwindling  operating  reserves and rolling  blackouts in parts of
California  in January and February 2001 have been widely  reported  nationwide.
These   shortages  of   electricity   have  been   attributed  to  flawed  state
restructuring  legislation,  unplanned  generating  plant  shutdowns  and  other
economic  factors.  In  response,  many  states  that had  passed or  considered
legislation  to restructure  the electric  industry have stopped such efforts or
are proceeding more slowly.

        In South Carolina, electric restructuring efforts have also stalled. The
developments unfolding in California, and several unrelated,  contentious issues
before the General  Assembly  have  combined to make  consideration  of electric
restructuring  legislation unlikely in 2001. Legislation or regulatory action at
the Federal level,  particularly as a part of a larger energy policy initiative,
may  be  considered  in  2001.   SCE&G  is  not  able  to  predict  whether  any
restructuring  legislation  or regulatory  action will be enacted and, if it is,
the conditions it will impose on utilities.

        SCE&G has undertaken a variety of  initiatives  aimed at preparing for a
restructured  electric market.  These initiatives include obtaining  accelerated
recovery of electric  regulatory assets,  establishing open access  transmission
tariffs and selling bulk power to wholesale  customers  at  market-based  rates.
Marketing of services to commercial and industrial  customers has also increased
significantly,  and SCE&G has obtained long term power supply  contracts  with a
significant  portion of its  industrial  customers.  SCE&G  believes  that these
actions,  as  well as  numerous  others  that  have  been  and  will  be  taken,
demonstrate  its ability and  commitment  to succeed in the  evolving  operating
environment.

       Regulated  public  utilities  are  allowed to record as assets some costs
that would be expensed by other enterprises. If deregulation or other changes in
the regulatory  environment occur, SCE&G may no longer be eligible to apply this
accounting  treatment and may be required to eliminate  such  regulatory  assets
from its balance sheet. Although the potential effects of deregulation cannot be
determined at present,  discontinuation of the accounting treatment could have a
material  adverse  effect on  SCE&G's  results of  operations  in the period the
write-off  would be recorded.  It is expected  that cash flows and the financial
position of SCE&G would not be materially affected by the discontinuation of the
accounting treatment.  SCE&G reported approximately $211 million and $65 million
of regulatory assets and liabilities,  respectively,  including amounts recorded
for deferred income tax assets and liabilities of approximately $129 million and
$52 million, respectively, on its balance sheet at December 31, 2000.



<PAGE>



       SCE&G's generation assets are 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, 2000,  SCE&G's net  investment  in
fossil/hydro  and  nuclear  generation  assets was  $1,154.9  million and $587.2
million, respectively.

LIQUIDITY AND CAPITAL RESOURCES

       The cash  requirements  of SCE&G  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, it may
be necessary to seek increases in rates. As a result,  SCE&G's future  financial
position  and  results of  operations  will be affected by its ability to obtain
adequate and timely rate and other regulatory relief, if requested.

       The revised  estimated  primary  cash  requirements  for 2001,  excluding
requirements for fuel liabilities and short-term  borrowings and including notes
payable to affiliated  companies,  and the actual primary cash  requirements for
2000 are as follows:

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


Property additions and construction
    expenditures, net of allowance for
   funds used during construction                   $396            $248
Nuclear fuel expenditures                             26              29
Investments                                            -               1
Maturing obligations, redemptions and
  sinking and purchase fund requirements               5             104
------------------------------------------------------------- --------------
            Total                                    $427           $382
============================================================== ==============

       Approximately  63 percent of total cash  requirements  (after  payment of
dividends) was provided from internal  sources in 2000 as compared to 69 percent
in 1999.

       SCE&G anticipates that its 2001 cash requirements of $427 million will be
met through internally generated funds (approximately 64 percent,  after payment
of  dividends)  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 next 12 months and for
the foreseeable future.

       SCE&G's First and Refunding Mortgage Bond Indenture,  dated April 1, 1945
(Old Mortgage), contains provisions prohibiting the issuance of additional bonds
thereunder  (Class A Bonds)  unless net  earnings  (as therein  defined)  for 12
consecutive  months out of the 18 months  prior to the month of issuance  are at
least  twice  the  annual  interest  requirements  on all  Class A  Bonds  to be
outstanding  (Bond Ratio).  For the year ended  December 31, 2000 the Bond Ratio
was 6.43. The Old Mortgage allows the issuance of additional Class A Bonds to an
additional  principal  amount  equal to (i) 70 percent of unfunded  net property
additions (which unfunded net property  additions totaled  approximately  $1,452
million  at  December  31,  2000),  (ii)  retirements  of  Class A Bonds  (which
retirement  credits totaled $68.4 million at December 31, 2000),  and (iii) cash
on deposit with the Trustee.

         SCE&G is 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 (of which $665 million were  available  for such purpose as of December
31,  2000).  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, 2000
the New Bond Ratio was 6.34.

         The following  additional  financing  transactions  have occurred since
January 1, 2000:

o      On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds having
       an annual  interest  rate of 7.50  percent and maturing on June 15, 2005.
       The  proceeds  from the sale of these bonds were used to pay the maturity
       of SCE&G's $100 million First Mortgage Bonds due June 15, 2000, to reduce
       short-term debt and for general corporate purposes.

o      On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having
       an annual interest rate of 6.70 percent and maturing on February 1, 2011.
       The proceeds from the sale of these bonds were used to reduce  short-term
       debt and for general corporate purposes.


         Without the consent of at least a majority of the total voting power of
SCE&G's   preferred  stock,   SCE&G  may  not  issue  or  assume  any  unsecured
indebtedness  if, after such issue or assumption,  the total principal amount of
all such  unsecured  indebtedness  would  exceed ten  percent  of the  aggregate
principal amount of all of SCE&G's secured indebtedness and capital and surplus;
however,  no such  consent is required to enter into  agreements  for payment of
principal,  interest and premium for  securities  issued for  pollution  control
purposes.

         Pursuant  to Section 204 of the  Federal  Power Act,  SCE&G must obtain
FERC authority to issue  short-term debt. The FERC has authorized SCE&G to issue
up to $250  million  of  unsecured  promissory  notes or  commercial  paper with
maturity dates of 12 months or less, but not later than December 31, 2002.

         At December 31, 2000 SCE&G had $250 million of unused  authorized lines
of credit which consists of a credit  agreement for a maximum of $250 million to
support the issuance of commercial paper.  SCE&G's  commercial paper outstanding
at  December  31,  2000  and  1999  was  $117.5  million  and  $143.1   million,
respectively.  In addition, Fuel Company has a credit agreement for a maximum of
$125  million with the full amount  available  at December 31, 2000.  The credit
agreement supports the issuance of short-term commercial paper for the financing
of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company
commercial  paper  outstanding  at  December  31, 2000 was $70.2  million.  This
commercial paper and amounts  outstanding  under the revolving credit agreement,
if any, are guaranteed by SCE&G.

         SCE&G's  Restated  Articles  of  Incorporation   prohibit  issuance  of
additional   shares  of  preferred   stock  without  consent  of  the  preferred
stockholders  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  (Preferred Stock Ratio).  For the year ended December 31, 2000 the
Preferred Stock Ratio was 2.09.

         On  September  21,  1999 SCE&G  announced  a $256  million  gas turbine
generator project in Aiken County, South Carolina.  Two combined-cycle  turbines
will burn natural gas to produce 300  megawatts of new electric  generation  and
use  exhaust  heat to replace  coal-fired  steam that  powers  two  existing  75
megawatt  turbines at the Urquhart  Generating  Station.  The turbine project is
scheduled to be completed by June 2002.

         On October 15, 1999 FERC notified  SCE&G of its agreement  with SCE&G's
plan to  reinforce  Lake Murray Dam in order to maintain  the lake in case of an
extreme  earthquake.  SCE&G  and  FERC  are  discussing  possible  reinforcement
alternatives  for the dam over the past several years as part of SCE&G's ongoing
hydroelectric  operating license with FERC. Until discussions are concluded,  it
is not  possible to finalize the cost of the  project;  however,  it is possible
that the cost could range up to $250  million.  Although  any costs  incurred by
SCE&G are  expected to be  recoverable  through  electric  rates,  SCE&G also is
exploring  alternative  sources  of  funding.  The  project  is  expected  to be
completed in 2004.

       On October 7, 2000 Summer  Station was removed from service for a planned
maintenance and refueling outage  scheduled to last 38 1/2 days.  During initial
inspection  activities,  plant  personnel  discovered a small leak coming from a
hole in a weld in a primary  coolant  system  pipe.  SCE&G  performed  extensive
ultrasonic testing of similar welds in the cooling system,  which confirmed that
the problem was limited to this single  weld. A root cause  analysis  determined
that the cause of the crack was primary  water stress  corrosion  cracking.  The
repair involved cutting out a twelve-inch long spool of the pipe, which included
the entire weld, and  installing a new spool piece.  Repairs have been completed
and the integrity of the new welds have been verified through extensive testing.
The plant was  returned to service in March 2001.  The NRC was closely  involved
throughout  this process and approved  SCE&G's  actions to repair the crack,  as
well as the restart  schedule.  SCE&G will continue to monitor  primary  coolant
system  pipes  during  the next  outage,  scheduled  for  Spring of 2002.  SCE&G
recorded a pretax charge of  approximately  $6 million in the fourth  quarter of
2000 to expense repair costs to date.  Additional  costs that may be recorded in
the  first  quarter  of 2001  are  not  expected  to be  material.  The  cost of
replacement  power is expected to be recovered  through  SCE&G's  electric  fuel
adjustment clause.

       In January 2001 SCE&G's 385 megawatt  coal-fired Cope Generating  Station
was taken out of service due to an electrical ground in the generator.  The unit
is expected to be returned to service in Spring  2001.  The cost of  replacement
power is expected to be recovered through SCE&G's fuel adjustment clause.

       SCANA and  Westvaco  each own a 50 percent  interest  in Cogen  South LLC
(Cogen).  Cogen was  formed to build and  operate  a  cogeneration  facility  at
Westvaco's Kraft Division Paper Mill in North  Charleston,  South Carolina.  The
facility began operations in March 1999. On September 10, 1998 the contractor in
charge of  construction  filed suit in Circuit Court seeking  approximately  $52
million  from  Cogen,  alleging  that it  incurred  construction  cost  overruns
relating  to the  facility,  and that the  construction  contract  provides  for
recovery of these costs.  In addition to Cogen,  Westvaco,  SCE&G and SCANA were
also named as defendants in the suit. SCE&G and the other defendants believe the
suit is without merit and are mounting an  appropriate  defense.  SCE&G does not
believe  that the  resolution  of this issue will have a material  impact on its
results of operations, cash flows or financial position.

Environmental Matters

         The CAA  required  electric  utilities  to reduce  emissions  of sulfur
dioxide and nitrogen oxide  substantially by the year 2000.  These  requirements
were  phased in over two  periods.  The first  phase  had a  compliance  date of
January 1, 1995 and the  second,  January 1, 2000.  SCE&G's  facilities  did not
require  modifications to meet the requirements of Phase I. SCE&G is meeting the
Phase II  requirements  through the burning of natural gas and/or  lower  sulfur
coal in its generating units and the purchase and use of sulfur dioxide emission
allowances.  Low nitrogen oxide burners have been  installed to reduce  nitrogen
oxide  emissions to the levels  required by Phase II. The EPA has indicated that
it will  propose  regulations  for  stricter  limits on mercury  and other toxic
pollutants  generated  by  coal-fired  plants by  December  2003 and will  begin
developing these regulations shortly.

         SCE&G  filed  compliance  plans  with DHEC  related  to Phase II sulfur
dioxide  requirements  in 1995 and  Phase II  oxides  of  nitrogen  oxide  (NOx)
requirements in 2000,  1999, 1998 and 1997.  SCE&G currently  estimates that air
emissions  control  equipment will require  capital  expenditures of $82 million
over the  2001-2005  period to  retrofit  existing  facilities,  with  increased
operation and maintenance  costs of  approximately  $2 million per year. To meet
compliance  requirements  for the years 2006  through  2010,  SCE&G  anticipates
additional capital expenditures of approximately $5 million.

         In  October  1998,  the EPA issued a final  rule  requiring  22 states,
including South Carolina,  to modify their state  implementation  plans (SIP) to
address the issue of NOx  pollution.  On May 25, 1999, a federal  appeals  court
delayed indefinitely the implementation of the rule. On March 3, 2000, the court
affirmed  the  EPA's  NOx rule  for the  affected  states.  South  Carolina  was
subsequently  ordered to amend its SIP to achieve  significant  NOx  reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and EPA
has issued  official  notice to South Carolina (and a number of other states) to
comply.  While not final,  South Carolina has proposed NOx reductions that would
require  SCE&G to install  pollution  control  equipment.  Because  DHEC had not
amended  its  SIP as of  December  31,  2000  to set  out or  allocate  any  NOx
reductions,  it is not possible to estimate what, if any,  capital  expenditures
will be required to comply with any potential mandated reductions.

         The EPA has undertaken an aggressive enforcement initiative against the
industry and the  Department  of Justice (DOJ) has brought suit against a number
of utilities  in federal  court  alleging  violations  of the CAA.  Prior to the
suits,  those utilities had received  requests for information under Section 114
of the CAA, and were issued Notices of Violation  prior to the suits.  The basis
for these suits is the claim 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 its Canadys and Wateree Stations.  Similar requests have
been sent to a number of other utilities nation wide. The regulations  under the
CAA provide  certain  exemptions  to the  definition  of "major  modifications,"
particularly an exemption for routine repair, replacement or maintenance.  SCE&G
has analyzed each of the  activities  covered by the EPA's requests and believes
each activity  represents  prudent practice regularly  performed  throughout the
utility industry as necessary to maintain the operational  efficiency and safety
of equipment.  As such,  SCE&G believes that each of these activities is covered
by the exemption for routine  repair,  replacement  and maintenance and that the
EPA is changing, or attempting to change through enforcement actions, the intent
and meaning of its  regulations.  SCE&G also believes that,  even if some of the
activities  in question  were found not to qualify  for the  routine  exemption,
there were no  increases  either in annual  emissions  or in the maximum  hourly
emissions  achievable at any of the units caused by any of the  activities.  The
regulations  provide an exemption for increased hours of operation or production
rate and for increases in emissions resulting from demand growth. It is possible
that the EPA will eventually commence enforcement actions against SCE&G relative
to those  plants.  The EPA has the  authority to seek  penalties for the alleged
violations in question at the rate of up to $27,500 per day for each  violation.
The EPA also would also seek  installation  of BACT (or equivalent) at the three
plants as well.  SCE&G  believes  that the EPA's and DOJ's  claims  are  without
merit, and that any enforcement  action, up to and including a lawsuit resulting
from this issue,  will not have a material  adverse effect on SCE&G's  financial
position or results of operations.

         The Federal Clean Water Act, as amended, provides for the imposition of
effluent  limitations  that require  various  levels of treatment for each waste
water  discharge.  Under this Act,  compliance  with  applicable  limitations is
achieved under a national permit program. Discharge permits have been issued for
all and  renewed for nearly all of SCE&G's  generating  units.  Concurrent  with
renewal of these permits,  the permitting agency has implemented a more rigorous
program in monitoring  and  controlling  thermal  discharges  and strategies for
toxicity reduction in wastewater streams.  SCE&G has been developing  compliance
plans for these  initiatives.  Amendments  to the Clean  Water Act  proposed  in
Congress  include several  provisions  which,  if passed,  could prove costly to
SCE&G.  These include,  but are not limited to,  limitations to mixing zones and
the  implementation  of  technology-based  standards.  In December  2000,  SCE&G
entered  into a Consent  Order with DHEC related to a  malfunction  of the waste
water treatment facility at Hagood Station.  The order requires SCE&G to correct
the violation.

         SCE&G  maintains an  environmental  assessment  program to identify and
assess  current and former  operations  sites that could  require  environmental
cleanup. As site assessments are initiated,  estimates are made of the amount of
expenditures,  if any,  deemed  necessary to investigate and clean up each site.
These  estimates  are  refined  as  additional  information  becomes  available;
therefore,  actual  expenditures  could differ  significantly  from the original
estimates.  Amounts  estimated  and  accrued  to date for site  assessments  and
cleanup relate primarily to regulated operations.  Such amounts are deferred and
amortized with recovery provided through rates.

         SCE&G has also  recovered  portions  of its  environmental  liabilities
through  settlements  with various  insurance  carriers,  including  all amounts
previously  deferred for its electric  operations.  SCE&G expects to recover all
deferred  amounts  related to its gas  operations  by  December  2005.  Deferred
amounts,  net of amounts  recovered  through  rates and  insurance  settlements,
totaled  $20.2  million  and  $23.7  million  at  December  31,  2000 and  1999,
respectively.  The deferral  includes the estimated  costs  associated  with the
following matters.

     o    In September 1992 the EPA notified  SCE&G,  the City of Charleston and
          the Charleston Housing Authority of their potential  liability for the
          investigation and cleanup of the Calhoun Park area site in Charleston,
          South  Carolina.  This  site  encompasses  approximately  30 acres and
          includes  properties  which were locations for industrial  operations,
          including  a  wood  preserving   (creosote)   plant,  one  of  SCE&G's
          decommissioned MGPs, properties owned by the National Park Service and
          the City of Charleston,  and private properties. The site has not been
          placed  on the  National  Priorities  List,  but may be  added  in the
          future. The PRPs negotiated an administrative order by consent for the
          conduct   of  a   Remedial   Investigation/Feasibility   Study  and  a
          corresponding  Scope of Work.  Field work began in November  1993, and
          the EPA approved a Remedial  Investigation Report in February 1997 and
          a Feasibility Study Report in June 1998. In July 1998 the EPA approved
          SCE&G's Removal Action Work Plan for soil excavation.  SCE&G completed
          Phase  One of the  Removal  Action  Work  Plan  in  1998  at a cost of
          approximately  $1.5 million.  Phase Two, which cost approximately $3.5
          million,  included  excavation and  installation of several  permanent
          barriers to mitigate coal tar seepage.  On September 30, 1998 a Record
          of Decision  was issued  which sets forth the EPA's view of the extent
          of each PRP's  responsibility  for site contamination and the level to
          which the site must be remediated.  SCE&G estimates that the Record of
          Decision will result in costs of approximately $13.3 million, of which
          approximately $2 million remains. On January 13, 1999 the EPA issued a
          Unilateral  Administrative  Order for  Remedial  Design  and  Remedial
          Action  directing  SCE&G to design and carry out a plan of remediation
          for the Calhoun Park site.  SCE&G submitted a  Comprehensive  Remedial
          Design Work Plan (RDWP) on  December  17,  1999,  and  proceeded  with
          implementation  pending agency approval.  The RDWP was approved by the
          EPA in July 2000, and its implementation continues.

               In October  1996 the City of  Charleston  and SCE&G  settled  all
               environmental   claims  the  City  may  have  had  against  SCE&G
               involving the Calhoun Park area for a payment of $26 million over
               four years  (1996-1999) by SCE&G to the City. SCE&G is recovering
               the  amount of the  settlement,  which  does not  encompass  site
               assessment and cleanup costs, through rates in the same manner as
               other  amounts  accrued  for  site  assessments  and  cleanup  as
               discussed above. As part of the environmental  settlement,  SCE&G
               constructed  an 1,100 space  parking  garage on the Calhoun  Park
               site  (construction  was completed in April 2000) and transferred
               the facility to the City in exchange for a $16.5 million, 18-year
               municipal bond  collaterized by revenues from, and a mortgage on,
               the parking garage.

          o    SCE&G owns three other  decommissioned  MGP sites  which  contain
               residues of by-product chemicals. For the site located in Sumter,
               South Carolina,  effective September 15, 1998, SCE&G entered into
               a Remedial  Action Plan  Contract  with DHEC pursuant to which it
               agreed to  undertake a full site  investigation  and  remediation
               under   the   oversight   of   DHEC.   Site   investigation   and
               characterization  are  proceeding  according  to  schedule.  Upon
               selection and successful  implementation  of a site remedy,  DHEC
               will give SCE&G a Certificate of  Completion,  and a covenant not
               to sue. For the site located in Florence,  South Carolina,  SCE&G
               entered into a similar  Remedial  Action Plan  Contract with DHEC
               effective  September 5, 2000.  SCE&G is continuing to investigate
               the remaining site in Columbia,  and is monitoring the nature and
               extent of residual contamination.

Regulatory Matters

        On July 20, 2000 the PSC issued an order  approving  SCE&G's request for
an  out-of-period  adjustment to increase the cost of gas component of its rates
for natural gas service  from 54.334  cents per therm to 68.835 cents per therm,
effective  with the first billing cycle in August 2000. As part of its regularly
scheduled  annual  review of gas costs,  the PSC issued an order on  November 9,
2000 which  further  increased  the cost of gas  component  to 78.151  cents per
therm,  effective with the first billing cycle in November 2000. On December 21,
2000 the PSC issued an order approving SCE&G's request for another out-of-period
adjustment  to increase  the cost of gas  component  to 99.340  cents per therm,
effective  with the first  billing  cycle in January 2001. In March 2001 the PSC
approved  SCE&G's  request to decrease the cost of gas component to 79.340 cents
per therm, effective with the first billing cycle in March 2001.

        On July 5, 2000 the PSC  approved  SCE&G's  request to  implement  lower
depreciation  rates  for  its  gas  operations.  The new  rates  were  effective
retroactively  to  January  1,  2000 and will  result in a  reduction  in annual
depreciation expense of approximately $2.9 million.

        On September 14, 1999 the PSC approved an accelerated  capital  recovery
plan for SCE&G's Cope Generating  Station.  The plan was  implemented  beginning
January 1, 2000 for a three-year period. The PSC approved an accelerated capital
recovery  methodology  wherein  SCE&G  may  increase  depreciation  of its  Cope
Generating  Station  in excess of  amounts  that  would be  recorded  based upon
currently   approved   depreciation   rates.   The  amount  of  the  accelerated
depreciation  will be  determined  by SCE&G based on the level of  revenues  and
operating  expenses,  not to exceed $36 million annually without the approval of
the PSC. Any unused  portion of the $36 million in any given year may be carried
forward for  possible  use in the  following  year.  As of December  31, 2000 no
accelerated  depreciation  has been recorded.  The accelerated  capital recovery
plan will be accomplished through existing customer rates.

       On December  11, 1998 the PSC issued an order  requiring  SCE&G to reduce
retail electric rates on a prospective basis. The PSC acted in response to SCE&G
reporting  that it earned a 13.04 percent return on common equity for its retail
electric  operations for the 12 months ended  September 30, 1998. This return on
common  equity  exceeded  SCE&G's  authorized  return  of 12.0  percent  by 1.04
percent,  or $22.7  million,  primarily  as a result of record heat  experienced
during the summer.  The order  required  prospective  rate  reductions  on a per
kilowatt-hour  basis,  based on actual  retail  sales  for the 12  months  ended
September  30,  1998.  On January  12,  1999 the PSC denied  SCE&G's  motion for
reconsideration,  ruled that no further rate action was required, and reaffirmed
SCE&G's  authorized  return on equity of 12.0 percent.  The rate reductions were
placed into effect with the first billing cycle of January 1999.

       On January 9, 1996 the PSC issued an order  granting SCE&G an increase in
retail  electric  rates which were fully  implemented  by January 1997.  The PSC
authorized  a return on common  equity of 12.0  percent.  The PSC also  approved
establishment  of a Storm  Damage  Reserve  Account  capped at $50 million to be
collected through rates over a ten-year period.  Additionally,  the PSC approved
accelerated  recovery of a significant  portion of SCE&G's  electric  regulatory
assets  (excluding  deferred  income tax  assets) and the  remaining  transition
obligation  for  postretirement  benefits  other  than  pensions,  changing  the
amortization  periods to allow  recovery  by the end of the year  2000.  SCE&G's
request  to shift,  for  rate-making  purposes,  approximately  $257  million of
depreciation  reserves  from  transmission  and  distribution  assets to nuclear
production  assets  was also  approved.  The  Consumer  Advocate  and two  other
intervenors appealed certain issues in the order initially to the Circuit Court,
which affirmed the PSC's decisions,  and subsequently,  to the Supreme Court. In
March  1998,  SCE&G,  the  PSC,  the  Consumer  Advocate  and  one of the  other
intervenors  reached an agreement that provided for the reversal of the shift in
depreciation  reserves and the dismissal of the appeal of all other issues.  The
PSC also authorized SCE&G to adjust depreciation rates that had been approved in
the 1996 rate order for its  electric  transmission,  distribution  and  nuclear
production  properties to eliminate the effect of the depreciation reserve shift
and to  retroactively  apply such  depreciation  rates to  February  1996.  As a
result,  a  one-time  reduction  in  depreciation  expense of $9.8  million  was
recorded in March 1998. The agreement does not affect retail electric rates. The
FERC had  previously  rejected the transfer of  depreciation  reserves for rates
subject to its  jurisdiction.  In September  1998 the Supreme Court affirmed the
Circuit Court's rulings on the issues contested by the remaining intervenor.

        In 1994 the PSC  issued an order  approving  SCE&G's  request to recover
through a billing  surcharge  to its gas  customers  the costs of  environmental
cleanup at the sites of former MGPs. The billing  surcharge is subject to annual
review and provides for the recovery of  substantially  all actual and projected
site  assessment  and cleanup costs and  environmental  claims  settlements  for
SCE&G's gas operations that had previously been deferred. In November 2000, as a
result of the annual review,  the PSC approved  SCE&G's  request to maintain the
billing  surcharge  at  $.011  per  therm to  provide  for the  recovery  of the
remaining balance of $20.1 million.

        In September 1992 the PSC issued an order granting SCE&G's request for a
$.25  increase in transit fares from $.50 to $.75 in Columbia,  South  Carolina;
however,  the PSC also required  $.40 fares for low income  customers and denied
SCE&G's request to reduce the number of routes and frequency of service. The new
rates were placed into effect in October 1992. SCE&G appealed the PSC's order to
the  Circuit  Court,  which in May  1995  ordered  the case  back to the PSC for
reconsideration  of  several  issues  including  the low income  rider  program,
routing  changes,  and the $.75 fare.  The Supreme  Court  declined to review an
appeal of the Circuit Court  decision and dismissed the case.  The PSC and other
intervenors filed another Petition for Reconsideration,  which the Supreme Court
denied.  The PSC and other intervenors filed another appeal to the Circuit Court
which the Circuit Court denied in an order dated May 9, 1996. In this order, the
Circuit Court upheld its previous  orders and remanded  them to the PSC.  During
August  1996 the PSC heard  oral  arguments  on the  orders  on remand  from the
Circuit  Court.  On  September  30, 1996 the PSC issued an order  affirming  its
previous orders and denied SCE&G's request for  reconsideration.  In response to
an appeal of the PSC's order by SCE&G,  the Circuit Court issued an order on May
25, 2000,  which  remanded the matter to the PSC for review of SCE&G's  original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC  issued  an order  granting  the  relief  requested  by  SCE&G.  On
September 29, 2000 the Consumer  Advocate filed a motion with the PSC for a stay
of this  order to which  SCE&G  filed a  response.  On  October  3, 2000 the PSC
accepted  the  Consumer  Advocate's  motion and issued a stay of its order.  The
Consumer  Advocate and other  intervenors  have petitioned the Circuit Court for
judicial review of the PSC's order granting relief.  Action by the Circuit Court
is pending.



<PAGE>



Other

        In June 1998 the  Financial  Accounting  Standards  Board (FASB)  issued
Statement  of  Financial   Accounting  Standards  (SFAS)  133,  "Accounting  for
Derivative  Instruments  and Hedging  Activities."  In June 2000 the FASB issued
SFAS 138,  which  amends  certain  provisions  of SFAS 133 to expand  the normal
purchase and sale exemption for supply  contracts and to redefine  interest rate
risk to reduce sources of ineffectiveness,  among other things. SCE&G's adoption
of SFAS 133,  as amended,  on January 1, 2001 did not have a material  impact on
SCE&G's results of operations, cash flows or financial position.

        In  December  1999,   Staff  Accounting   Bulletin  No.  101,   "Revenue
Recognition in Financial Statements" was issued by the SEC, and provides the SEC
staff's views in applying generally accepted  accounting  principles to selected
revenue  recognition  issues.  SCE&G's  adoption  of the  bulletin in the fourth
quarter  of 2000 had no impact  on its  results  of  operations,  cash  flows or
financial position.

RESULTS OF OPERATIONS

Net Income

    Net income and the percent change from the previous year for the years 2000,
1999 and 1998 were as follows:

Millions of dollars                           2000       1999         1998
--------------------------------------------------------------------------------
Net income derived from:
  Continuing operations                      $231.3      $189.2      $227.2
  Cumulative effect of accounting change      $22.3           -           -
================================================================================
  Net income                                 $253.6      $189.2      $227.2
================================================================================
Percent increase (decrease) in net income     34.04%     (16.75%)     16.72%
--------------------------------------------------------------------------------

o    2000 vs 1999    Net income  increased  primarily as a result of more
                     favorable  weather,  customer  growth and pension
                     income.  These were  partially  offset by higher purchased
                     power  costs and a charge for repairs at Summer Station.


o    1999 vs 1998    Net income decreased primarily due to a rate reduction,
                     milder weather, and higher fuel costs. In addition,
                     completion of a new customer billing system and
                     cogeneration facility, among other factors, resulted in
                     increased operating and depreciation expenses. These
                     factors were partially offset by customer growth.  Also
                     affecting the decrease in net income was the depreciation
                     reduction recorded in 1998 (as discussed below).

     Pension  income  recorded  by SCE&G  reduced  operations  expense  by $20.9
million,  $16.3 million and $16.6 million for the years ended December 31, 2000,
1999 and 1998, respectively.  In addition, pension income increased other income
by $12.9  million,  $10.5 million and $9.0 million for the years ended  December
31, 2000, 1999 and 1998, respectively.  The reductions to operations expense for
1999 and  1998  were  substantially  offset  by  accelerated  amortization  of a
significant  portion of the transition  obligation for  postretirement  benefits
other than  pensions  and  certain  regulatory  assets as  approved  by the PSC.
Effective  July 1, 2000  SCE&G's  pension  plan was  amended  to  provide a cash
balance  formula.  The effect of this plan  amendment was to reduce net periodic
benefit  income for the year  ended  December  31,  2000 by  approximately  $3.4
million.

     SCE&G's  financial  statements  include  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  1.7 percent of income before income
taxes in 2000, 2.0 percent in 1999 and 3.8 percent in 1998.



<PAGE>



Electric Operations

     Electric  Operations is comprised of the electric portion of SCE&G and Fuel
Company.  Electric operations sales margins,  excluding the cumulative effect of
accounting change, for 2000, 1999 and 1998 were as follows:

Millions of dollars                            2000       1999       1998
------------------------------------------------------------------------------

Electric revenue                             $1,343.8   $1,226.0   $1,219.8

Less:  Fuel used in electric generation        (231.6)    (214.4)    (212.3)

           Purchased power                     (182.7)    (141.5)    (116.4)
------------------------------------------------------------------------------
      Margin                                   $929.5     $870.1     $891.1
==============================================================================

o        2000 vs 1999 Sales margin increased primarily due to more favorable
                      weather and customer growth, which was
                      partially offset by higher purchased power costs.

o        1999 vs 1998 Sales margin decreased primarily due to the impact of a
                      rate reduction, milder weather and higher
                      purchased power costs, which were partially offset by
                      customer growth.

      Increases  (decreases)  from the prior year in  megawatt-hour  (MWH) sales
volume by classes,  excluding  volumes  attributable to the cumulative effect of
accounting change, were as follows: <TABLE>

    Classification                   2000       % Change        1999        % Change
    ------------------------------------------ ------------ ------------- -------------

<S>                                   <C>           <C>         <C>           <C>
    Residential                       396,179       6.3%        (55,208)      (0.9%)
    Commercial                        353,621      5.9%          52,440        0.9%
    Industrial                        524,969      8.5%        316,087         5.4%

    Sales for Resale
    (excluding interchange)            33,505         2.8%          63,306        5.6%

    Other                              34,676         6.7%         (17,652)      (3.3%)
    ------------------------------------------              -------------
          Total territorial         1,342,950       6.7%        358,973             -
    Negotiated Market Sales Tariff    264,257      15.7%        183,442       12.3%
    ------------------------------------------              -------------
         Total                      1,607,207        7.4%        542,415         2.6%
    ========================================== ============ ============= =============
</TABLE>

o   2000 vs 1999     Sales volume increased primarily due to more favorable
                     weather and customer growth.

o   1999 vs 1998     Sales volume decreased for residential primarily due to
                     milder weather, which was partially offset by
                     customer growth.  Volumes for the remaining classes
                     increased primarily due to customer growth.

Gas Distribution

   Gas Distribution is comprised of the local distribution  operations of SCE&G.
Gas distribution  sales margins,  excluding the cumulative  effect of accounting
change, for 2000, 1999 and 1998 were as follows:

    Millions of dollars               2000         1999        1998
    --------------------------------------------- -------------- ------------

    Gas operating revenues            $325.1     $239.0       $230.4
    Less:  Gas purchased for resale    233.8      152.6        142.4
    --------------------------------------------- -------------- ------------

           Margin                     $91.3       $86.4        $88.0
    ============================================= ============== ============


o   2000 vs 1999     Sales margin increased primarily as a result of  more
                     favorable weather, which was partially offset
                     by higher gas costs.

o   1999 vs 1998     Sales margin decreased primarily as a result of higher gas
                     costs.



<PAGE>




 Increases  (decreases)  from the prior year in  dekatherm  (DT) sales volume by
classes,  including transportation gas and excluding volumes attributable to the
cumulative effect of accounting change, were as follows:

    Classification        2000      % Change         1999      % Change
    ------------------------------- ------------- ------------ ------------
    Residential           411,985        3.5%        (94,027)     (0.8%)
    Commercial            377,347        3.2%       404,654        3.6%
    Industrial           (828,737)      (4.6%)      644,485        3.7%
    Transportation gas    110,220        5.6%       (28,732)     (1.4%)
                          -------                  --------
        Total              70,815        0.2%       926,380       2.2%
    =============================== ============= ============ ============

o                     2000  vs  1999Sales  volume  increased  approximately  2.0
                      million  DTs due to colder  weather and  customer  growth,
                      which  was  partially  offset by  curtailments  and use of
                      alternate fuels by industrial customers.

o  1999 vs 1998      Sales volume increased primarily as a result of customer
                     growth.  Residential volume decreased
                     primarily due to milder weather.

Other Operating Expenses

     Increases (decreases) in other operating expenses were as follows:

Millions of dollars                  2000                  1999
-------------------------------------------------- ---------------------

Other operation and maintenance       $(8.2)                $7.0
Depreciation and amortization           4.8                 22.3
Other taxes                             3.5                  1.8
-------------------------------------------------- ---------------
       Total                           $0.1                $31.1
================================================== ===============

o                     2000 vs 1999Other operation and maintenance  decreased due
                      to pension  income (see Net Income),  which was  partially
                      offset  by  increased   maintenance   costs  for  electric
                      generating and distribution  facilities.  Depreciation and
                      amortization  increased  primarily due to normal increases
                      in utility plant.  Other taxes increased  primarily due to
                      increased property taxes.

o  1999 vs 1998      Other operation and  maintenance increased primarily due to
                     a shift in labor from capital to expense
                     related to the completion of a new customer billing system,
                     a cogeneration facility becoming operational, and other
                     operating costs.  These costs were partially offset by
                     pension income, which in 1998 had been offset by the
                     accelerated amortization of SCE&G's transition obligation
                     expense for post-retirement benefits and other regulatory
                     assets. Depreciation and amortization increased
                     primarily due to the  impact of the non-recurring
                     adjustment to depreciation expense discussed under
                     Net Income, increased amortization due to completion of a
                     new customer billing system, and normal increases in
                     utility plant. Other taxes increased primarily due to
                     increased property taxes.

Interest Expense

     Increases (decreases) in interest expense,  excluding the debt component of
AFC, were as follows:

Millions of dollars                 2000                    1999
------------------------------------------------ ---------------------

Interest on long-term debt, net     $4.0                      $1.9
Other interest expense              (0.5)                      2.4
------------------------------------------------- ---------------------
       Total                        $3.5                      $4.3
================================================= =====================

     Interest expense in 2000 increased as a result of increased  borrowings and
increased   weighted   average   interest  rates  on  short-term  and  long-term
borrowings.  Interest  expense  in  1999  increased  as a  result  of  increased
borrowings.



<PAGE>



Income Taxes

     Income  taxes  increased  approximately  $23.4  million  for the year  2000
compared to 1999 and  decreased  approximately  $22.4 million for the year ended
1999  compared to 1998.  Changes in income taxes are primarily due to changes in
operating income.


 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

     Interest  rate risk - The table below  provides  information  about SCE&G's
financial  instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates. <TABLE>

December 31, 2000                                                  Expected Maturity Date
Millions of dollars

Liabilities                    2001         2002        2003        2004        2005      Thereafter      Total      Fair Value
-----------                    ----         ----        ----        ----        ----      ----------      -----      ----------
--------------------------- ------------ ----------- ----------- ----------- ----------- ------------- ------------- ------------

     Long-Term Debt:
<S>             <C>             <C>         <C>        <C>          <C>        <C>           <C>         <C>           <C>
     Fixed Rate ($)             27.6        27.6       129.5        123.9      173.9         932.5       1,415.0       1,331.6
-------------------
     Average Interest Rate     6.72%       6.72%        6.37%        7.52%      7.40%        7.55%           7.39%

December 31, 1999                                                  Expected Maturity Date
Millions of dollars

Liabilities                    2000         2001        2002        2003        2004      Thereafter      Total      Fair Value
--------------------------- ------------ ----------- ----------- ----------- ----------- ------------- ------------- ------------

     Long-Term Debt:

<S>             <C>              <C>         <C>         <C>         <C>         <C>     <C>              <C>           <C>
     Fixed Rate ($)              127.5       27.6        27.6        129.4       123.9   933.0            1,369.0       1,232.7
     Average Interest Rate        6.16%      6.73%       6.73%        6.37%       7.52%         7.72%         7.39%
</TABLE>

     While a decrease in interest  rates would  increase the fair value of debt,
it is unlikely that events which would result in a realized loss will occur.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         INDEX TO CONSOLIDATED FINANCIAL
                        STATEMENTS AND SUPPLEMENTARY DATA
                                                                          Page

Independent Auditors' Report............................................... 85

Consolidated Financial Statements:

    Consolidated Balance Sheets as of December 31, 2000 and 1999........... 86

    Consolidated Statements of Income and Retained Earnings
        for years ended December 31, 2000, 1999 and 1998................... 88

    Consolidated Statements of Cash Flows for the years ended
       December 31, 2000, 1999 and 1998.................................... 89

    Consolidated Statements of Capitalization as of December
        31, 2000  and 1999................................................. 90

    Notes to Consolidated Financial Statements............................. 92


<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, 2000 and 1999 and the related Consolidated Statements of Income and Retained
Earnings and Cash Flows for each of the three years in the period ended December
31, 2000. Our audits also included the financial  statement  schedule  listed in
Part IV at Item 14. These financial  statements and financial statement schedule
are the  responsibility of the Company's  management.  Our  responsibility is to
express  an  opinion  on these  financial  statements  and  financial  statement
schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit to obtain  reasonable  assurance  about  whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In our opinion,  such consolidated  financial  statements present fairly, in all
material  respects,  the financial  position of the Company at December 31, 2000
and 1999 and the  results of its  operations  and its cash flows for each of the
three years in the period ended December 31, 2000 in conformity  with accounting
principles  generally  accepted in the United  States of America.  Also,  in our
opinion,  such financial statement schedule,  when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

As  discussed  in Note 2 to the  consolidated  financial  statements,  effective
January 1, 2000,  the Company  changed its method of  accounting  for  operating
revenues.


s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 2001












<PAGE>


<TABLE>

                                           SOUTH CAROLINA ELECTRIC & GAS COMPANY
                                                CONSOLIDATED BALANCE SHEETS

----------------------------------------------------------------------------- ----------------- -------------------
December 31, (Millions of dollars)                                                  2000               1999
----------------------------------------------------------------------------- ----------------- -------------------
Assets
Utility Plant (Notes 1 & 5):
<S>                                                                                <C>                <C>
    Electric                                                                       $4,453             $4,337
    Gas                                                                                409                392
    Other                                                                              186                191
----------------------------------------------------------------------------- ----------------- -------------------
        Total                                                                       5,048              4,920
    Less accumulated depreciation and amortization                                  1,720              1,611
----------------------------------------------------------------------------- ----------------- -------------------
        Total                                                                       3,328              3,309
    Construction work in progress                                                      230                149
    Nuclear fuel, net of accumulated amortization                                        57                43
----------------------------------------------------------------------------- ----------------- -------------------
        Utility Plant, Net                                                          3,615              3,501
----------------------------------------------------------------------------- ----------------- -------------------

Nonutility Property and Investments, net of accumulated depreciation                    21                 19
----------------------------------------------------------------------------- ----------------- -------------------

Current Assets:
    Cash and temporary cash investments (Notes 1 &11)                                    60                78
    Receivables                                                                        287                195
    Inventories (At average cost) (Note 6):
        Fuel                                                                            21                 30
        Materials and supplies                                                          46                 48
        Emission allowances                                                             20                 17
    Prepayments                                                                           5                  8
    Deferred income taxes, net  (Notes 1 & 10)                                            -                16
----------------------------------------------------------------------------- ----------------- -------------------
        Total Current Assets                                                           439                392
----------------------------------------------------------------------------- ----------------- -------------------

Deferred Debits:
    Emission allowances                                                                   3                14
    Environmental                                                                       20                 24
    Nuclear plant decommissioning fund  (Note 1)                                        72                 64
    Pension asset, net  (Note 4)                                                       196                144
    Other regulatory assets (Note 1)                                                   191                164
    Other                                                                              107                 82
----------------------------------------------------------------------------- ----------------- -------------------
        Total Deferred Debits                                                          589                492
----------------------------------------------------------------------------- ----------------- -------------------
            Total                                                                  $4,664              $4,404
============================================================================= ================= ===================








<PAGE>



   SOUTH CAROLINA ELECTRIC & GAS COMPANY
   CONSOLIDATED BALANCE  SHEETS
     ----------------------------------------------------------------------- -------------------- --------------------
     December 31, (Millions of dollars)                                             2000                 1999
     ----------------------------------------------------------------------- -------------------- --------------------
     Capitalization and Liabilities
     Stockholders' Investment:
<S>                           <C>                                                  <C>                  <C>
         Common equity  (Note 8)                                                   $1,657               $1,558
         Preferred stock (Not subject to purchase or sinking funds) (Note
     9)                                                                                106                  106
     ----------------------------------------------------------------------- -------------------- --------------------
             Total Stockholders' Investment                                         1,763                 1,664
     Preferred Stock, net (Subject to purchase or sinking funds)                        10                    11
     Company-Obligated   Mandatorily  Redeemable  Preferred  Securities  of  the
         Company's  Subsidiary Trust,  SCE&G Trust I, holding solely $50 million
         principal amount of the 7.55%
         Junior Subordinated Debentures of SCE&G, due 2027                               50                   50
     Long-Term Debt, net  (Notes 5 & 11)                                             1,267                1,121
     ----------------------------------------------------------------------- -------------------- --------------------
             Total Capitalization                                                    3,090                2,846
     ----------------------------------------------------------------------- -------------------- --------------------

     Current Liabilities:
         Short-term borrowings  (Notes 6, 7 & 11)                                      188                   213
         Current portion of long-term debt  (Note 5)                                     28                  128
         Accounts payable                                                              103                    78
         Accounts payable - affiliated companies (Note 1)                                58                   33
         Customer deposits                                                               17                   17
         Taxes accrued                                                                   51                   60
         Interest accrued                                                                22                   22
         Dividends declared                                                              44                   28
         Deferred income taxes, net  (Notes 1 & 10)                                      20                     -
         Other                                                                           10                   10
     ----------------------------------------------------------------------- -------------------- --------------------
            Total Current Liabilities                                                   541                  589
     ----------------------------------------------------------------------- -------------------- --------------------

     Deferred Credits:
         Deferred income taxes, net  (Notes 1 & 10)                                     584                  560
         Deferred investment tax credits (Notes 1 & 10)                                 109                  108
         Reserve for nuclear plant decommissioning  (Note 1)                             72                   64
         Postretirement benefits  (Note 4)                                             113                    98
         Other regulatory liabilities                                                    65                   59
         Other (Note 1)                                                                  90                  80
     ----------------------------------------------------------------------- -------------------- --------------------
             Total Deferred Credits                                                  1,033                  969
     ----------------------------------------------------------------------- -------------------- --------------------

     Commitments and Contingencies (Note 12)                                              -                    -
     ----------------------------------------------------------------------- -------------------- --------------------

                Total                                                                 $4,664            $4,404
     ======================================================================= ==================== ====================

   See Notes to Consolidated Financial Statements.




<PAGE>




SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

----------------------------------------------------------------------- ------------------ ---------------- --------------- --
For the Years Ended December 31,                                              2000              1999             1998
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
(Millions of Dollars, except per share amounts)

Operating Revenues (Notes 1, 2 & 3):
<S>                                                                          <C>                 <C>               <C>
    Electric                                                                 $1,344              $1,226            $1,220
    Gas                                                                          325              239              230
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
        Total Operating Revenues                                               1,669            1,465            1,450
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Operating Expenses:
    Fuel used in electric generation                                             232              214              212
    Purchased power (including affiliated purchases of $100, $106 and
$185)                                                                            183              142              116
    Gas purchased for resale                                                     234              153              142
    Other operation and maintenance (Note 1)                                     308              316              309
    Depreciation and amortization (Note 1)                                       158              153              131
    Other taxes                                                                    97              94               92
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
        Total Operating Expenses                                               1,212            1,072           1,002
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Operating Income                                                                 457              393              448
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Other Income:
    Other Income, including allowance for equity funds used
       during construction (Note 1)                                               14                 9               9
    Gain on sale of assets                                                          2                3                -
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
        Total Other Income                                                        16               12                9
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Interest Charges, Income Taxes, Preferred Stock
Dividends
   and Cumulative Effect of Accounting Change                                    473              405             457
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Interest Charges:
    Interest expense on long-term debt, net                                      101                97              95
    Other interest expense, net of allowance for borrowed funds used
         during construction  (Note 1)                                             4                 5              (1)
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
        Total Interest Charges, Net                                              105              102               94
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Income Taxes, Preferred Stock Dividends
    and  Cumulative Effect of Accounting Change                                  368              303              363
Income Taxes (Note 10)                                                           133              110              132
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Preferred Stock Dividends and Cumulative
   Effect of Accounting Change                                                   235              193             231
Preferred Dividend Requirement of Company - Obligated
   Mandatorily Redeemable Preferred Securities                                     4                4                4
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Cumulative Effect of Accounting Change                             231              189             227
Cumulative Effect of Accounting Change, net of taxes  (Note 2)                    22                  -              -
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Net Income                                                                       253              189             227
Preferred Stock Cash Dividends (At stated rates)                                  (7)               (7)             (8)
----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Earnings Available for Common Stockholder                                        246              182                 219
Retained Earnings at Beginning of Year                                           550              491                 438
Common Stock Cash Dividends Declared                                            (147)            (123)           (166)
======================================================================= ================== ================ =============== ==
Retained Earnings at End of Year                                               $649                 $550            $491
======================================================================= ================== ================ =============== ==

See Notes to Consolidated Financial Statements.



<PAGE>




SOUTH CAROLINA ELECTRIC & GAS COMPANY
  CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,                                          2000          1999          1998
---------------------------------------------------------------------- ------------ ------------- -------------
(Millions of dollars)

Cash Flows From Operating Activities:
<S>                                                                       <C>           <C>           <C>
Net income                                                                $253          $189          $227
Adjustments  to  reconcile  net  income  to net  cash  provided  from  operating
  activities:
    Cumulative effect of accounting change, net of taxes                    (22)            -            -
    Depreciation and amortization                                          159          154           131
    Amortization of nuclear fuel                                             16           18            20
    Allowance for funds used during construction                             (6)          (6)          (14)
    Over (under) collection, fuel adjustment clause                         (42)          (6)            1
    Changes in certain assets and liabilities:
         (Increase) decrease in receivables                                (56)          (17)          (13)
         (Increase) decrease in pension asset                               (43)         (29)          (33)
         (Increase) decrease in other regulatory assets                      15           16           (23)
         (Increase) decrease inventories                                      8          (16)           (8)
         Increase (decrease) in deferred income taxes, net                   60           16            49
         Increase (decrease) in postretirement benefits                      15           11            26
         Increase (decrease) in other regulatory liabilities                  6            (6)           4
         Increase (decrease) in accounts payable                            50            (9)          35
         Increase (decrease) in taxes accrued                              (23)          (15)          30
   Other, net                                                               (11)          10             9
---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From Operating Activities                                379          310           441
---------------------------------------------------------------------- ------------ ------------- -------------

Cash Flows From Investing Activities:
  Utility property additions and construction expenditures, net of
AFC                                                                       (277)        (227)         (252)
  Proceeds on sales of assets                                                 1            3             -
  (Increase) decrease in nonutility property and investments                 (1)          (6)           (1)
---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Investing Activities                                    (277)        (230)         (253)
---------------------------------------------------------------------- ------------ ------------- -------------

Cash Flows From Financing Activities:
    Proceeds:
        Issuance of First Mortgage Bonds                                   148            99             -
    Repayment and repurchases:
        Mortgage bonds                                                    (100)         (10)           (50)
        Notes and loans                                                       -           -            (10)
        Other long-term debt                                                 (4)          (9)             -
        Preferred stock                                                      (1)           -            (1)
    Dividend payments:
        Common Stock                                                      (131)        (133)         (187)
        Preferred stock                                                      (7)          (7)           (8)
    Short-term borrowings, net                                              (25)          88           112
    Fuel financings, net                                                      -          (66)          (14)
---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From (Used For) Financing Activities                    (120)          (38)        (158)
---------------------------------------------------------------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Temporary Cash Investments              (18)          42            30
Cash and Temporary Cash Investments, January 1                               78           36              6
====================================================================== ============ ============= =============
Cash and Temporary Cash Investments, December 31                           $60           $78           $36
====================================================================== ============ ============= =============

Supplemental Cash Flow Information:
   Cash paid for - Interest (net of  capitalized interest of  $4, $3
and $7)                                                                   $102          $99           $94
                          - Income taxes                                     97          109            92

See Notes to Consolidated Financial Statements.



<PAGE>






SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

--------------------------------------------------------------------------------- ------------- ------ ------------- ------
December 31, (Millions of dollars)                                                    2000                 1999
--------------------------------------------------------------------------------- ------------- ------ ------------- ------

Common Equity (Note 8):
  Common stock, $4.50 par value, authorized 50,000,000 shares;
<S>                          <C>                                                       <C>                 <C>
      issued and outstanding 40,296,147 shares                                         $181                $181
  Premium on common stock                                                               395                  395
  Other paid-in capital                                                                 437                  437
  Capital stock expense                                                                   (5)                  (5)
  Retained earnings                                                                     649                  550
--------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Common Equity                                                                   1,657       54%      1,558       55%
--------------------------------------------------------------------------------- ------------- ------ ------------- ------

Cumulative Preferred Stock (Not subject to purchase or sinking funds):
        $100 Par Value - Authorized 1,200,000 shares
          $50 Par Value - Authorized 125,209 shares
                                            Shares
                             Outstanding                    Redemption Price

                Series            2000         1999
                ------            ----         ----
        $100
Par             6.52%          1,000,000    1,000,000            100.00                 100                  100
          $50
Par             5.00%             125,209      125,209            52.50                    6                    6
--------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Preferred Stock (Not subject to purchase or sinking funds) (Note 9)               106        3%        106        4%
--------------------------------------------------------------------------------- ------------- ------ ------------- ------

Cumulative Preferred Stock (Subject to purchase and sinking funds):

       $100 Par Value - Authorized  1,550,000  shares;  None outstanding in 2000
         and 1999 $50 Par Value - Authorized 1,560,287 shares

                                 Shares Outstanding

                 Series           2000         1999         Redemption Price
                 ------           ----         ----         ----------------

                 4.50%             9,600       11,200            51.00                     1                   1
                 4.60% (A)        16,052       18,082            51.00                     1                   1
                 4.60% (B)        57,800       61,200            50.50                     3                   3
                 5.125%           67,000       68,000            51.00                     3                   3
                 6.00%            69,835       73,035            50.50                     3                   4
                              ------------- -----------
          Total                 220,287      231,487
                              ============= ===========

           $25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999

---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock  (Subject to purchase or sinking funds)                            11                   12
Less:  Current portion, including sinking funds requirements                             (1)                  (1)
---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11)         10          -%       11         -%
---------------------------------------------------------------------------------- ------------ -------- ----------- -------

Company-Obligated  Mandatorily  Redeemable  Preferred  Securities  of  Company's
   Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
   of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 9)                   50          2%      50          2%
---------------------------------------------------------------------------------- ------------ -------- ----------- -------



<PAGE>










     ----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
     December 31, (Millions of dollars)                                          2000                    1999
     ----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
     Long-Term Debt  (Notes 5 & 11)

     First Mortgage Bonds:
                           Series          Year of Maturity
                           6%                    2000                                 -                    100
                           6 1/4%                2003                              100                     100
                           7.70%                 2004                              100                     100
                           7 1/2%                2005                              150                        -
                           6 1/8%                2009                              100                     100
                           7 1/8%                2013                              150                     150
                           7 1/2%                2023                              150                     150
                           7 5/8%                2023                              100                     100
                           7 5/8%                2025                              100                     100

     First and Refunding Mortgage Bonds:

                           Series          Year of Maturity
                           9%                    2006                              131                     131
                           8 7/8%                2021                              103                     103

     Pollution Control Facilities Revenue Bonds:
        Fairfield County Series 1984, due 2014 (6.50%)                               57                     57
        Orangeburg County Series 1994, due 2024 (5.70%)                              30                     30
        Other                                                                       17                      17
     Charleston Franchise Agreement due 1997-2002                                     7                     11
     Other                                                                            3                       3
     ----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
     Total Long-Term Debt                                                        1,298                   1,252
     Less  -  Current maturities, including sinking fund
     requirements                                                                   (28)                     (128)
              -  Unamortized discount                                                (3)                     (3)
     ----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
     Total Long-Term Debt, Net                                                   1,267         41%       1,121          39%
     ----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
     Total Capitalization                                                         $3,090     100%        $2,846        100%
     =========================================================== =========== ============== ======== ============== ===========
</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

       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 (PUHCA). The Company is engaged predominately in the generation and sale of
electricity  to  wholesale  and retail  customers  in South  Carolina and in the
purchase,  sale and  transportation  of natural gas to retail customers in South
Carolina.

       The accompanying  Consolidated  Financial Statements reflect the accounts
of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust
I. Intercompany  balances and transactions between the Company, Fuel Company and
SCE&G Trust I have been eliminated in consolidation.

Affiliated Transactions

       The  Company has entered  into  agreements  with  certain  affiliates  to
purchase gas for resale to its distribution  customers and to purchase  electric
energy.  The Company purchases all of its natural gas requirements from Pipeline
Corporation,  and at December 31, 2000 and 1999,  the Company had  approximately
$45.9 million and $20.9 million,  respectively,  payable to Pipeline Corporation
for such gas purchases.  The Company purchases all of the electric generation of
Williams Station,  which is owned by GENCO,  under a unit power sales agreement.
At December  31, 2000 and 1999 the Company had  approximately  $8.3  million and
$9.2 million, respectively, payable to GENCO for unit power purchases. Such unit
power  purchases,   which  are  included  in  "Purchased   power,"  amounted  to
approximately $100.2 million, $105.5 million and $85.0 million in 2000, 1999 and
1998, respectively.

       Total interest  income,  based on market interest rates,  associated with
the Company's  advances to affiliated  companies was  approximately  $1,086,000,
$921,000 and $281,000 in 2000, 1999 and 1998, respectively.

B.     Basis of Accounting

       The Company  accounts for its regulated  utility  operations,  assets and
liabilities  in  accordance  with  the  provisions  of  Statement  of  Financial
Accounting  Standards (SFAS) 71. This accounting  standard  requires  cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses  in  different   time  periods  than  do   enterprises   that  are  not
rate-regulated.  As a result the Company has recorded,  as of December 31, 2000,
approximately $211 million and $65 million of regulatory assets and liabilities,
respectively,  including  amounts  recorded for  deferred  income tax assets and
liabilities of  approximately  $129 million and $52 million,  respectively.  The
electric and gas regulatory assets of approximately $45 million and $37 million,
respectively  (excluding  deferred  income tax assets) are  recoverable  through
rates.  In the  future,  as a result of  deregulation  or other  changes  in the
regulatory  environment,  the  Company  may no  longer  meet  the  criteria  for
continued  application  of  SFAS 71 and  could  be  required  to  write  off its
regulatory  assets and liabilities.  Such an event could have a material adverse
effect on the Company's  results of operations in the period the write-off would
be recorded,  but it is not expected that cash flows or financial position would
be materially affected.

C.     System of Accounts

       The accounting  records of the Company are maintained in accordance  with
the Uniform  System of Accounts  prescribed  by the  Federal  Energy  Regulatory
Commission (FERC) and as adopted by the South Carolina Public Service Commission
(PSC).

D.     Utility Plant

       Utility  plant is stated  substantially  at original  cost.  The costs of
additions,  renewals and betterments to utility plant,  including  direct labor,
material and indirect charges for engineering,  supervision and an allowance for
funds  used  during  construction,  are added to  utility  plant  accounts.  The
original cost of utility  property  retired or otherwise  disposed of is removed
from  utility  plant  accounts  and  generally  charged,  along with the cost of
removal,  less  salvage,  to  accumulated  depreciation.  The costs of  repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.

       The  Company,  operator  of the V.  C.  Summer  Nuclear  Station  (Summer
Station),  and the South Carolina Public Service  Authority  (Santee Cooper) are
joint owners of Summer  Station in the  proportions of two-thirds and one-third,
respectively.  The parties  share the  operating  costs and energy output of the
plant in these  proportions.  Each party,  however,  provides its own financing.
Plant-in-service  related  to  the  Company's  portion  of  Summer  Station  was
approximately  $965.0  million and $959.7  million as of  December  31, 2000 and
1999, respectively. Accumulated depreciation associated with the Company's share
of Summer  Station was  approximately  $387.7  million and $365.1  million as of
December  31, 2000 and 1999,  respectively.  The  Company's  share of the direct
expenses  associated  with  operating  Summer  Station  is  included  in  "Other
operation and maintenance" expenses.

E.     Allowance for Funds Used During Construction (AFC)

       AFC, a noncash item, reflects the period cost of capital devoted to plant
under  construction.  This accounting practice results in the inclusion of, as a
component of construction  cost, the costs of debt and equity capital  dedicated
to  construction  investment.  AFC is  included  in  rate  base  investment  and
depreciated  as a  component  of plant cost in  establishing  rates for  utility
services. The Company has calculated AFC using composite rates of 8.1%, 7.7% and
8.5% for 2000,  1999 and  1998,  respectively.  These  rates do not  exceed  the
maximum  allowable  rate as  calculated  under FERC Order No.  561.  Interest on
nuclear fuel in process is capitalized at the actual interest amount incurred.

F.     Revenue Recognition

         Revenues are recorded  during the  accounting  period in which services
are provided to customers,  and include  estimated  amounts for  electricity and
natural  gas  delivered  but not yet billed.  Prior to January 1, 2000  revenues
related to regulated  electric and gas services  were recorded only as customers
were billed (see Note 2).

       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 PSC 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  $35.5 million and $10.1 million
at December  31, 2000 and 1999,  respectively,  which are  included in "Deferred
Debits - Other regulatory assets."

       Customers subject to the gas cost adjustment clause are billed based on a
fixed  cost of gas  determined  by the  PSC  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,  2000  and  1999  the  Company  had
undercollected  through  the gas cost  recovery  procedure  approximately  $12.7
million and $4.1 million,  respectively,  which are included in "Deferred Debits
Other regulatory assets."

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

G.     Depreciation and Amortization

       Provisions  for  depreciation  and  amortization  are recorded  using the
straight-line method and are based on the estimated service lives of the various
classes of property.  The  composite  weighted  average  depreciation  rates for
utility  plant  assets  were  2.98%,  2.99% and  3.02% for 2000,  1999 and 1998,
respectively.


<PAGE>




       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 ownership
interest  in the  station.  The cost  estimate  is  based  on a  decommissioning
methodology  acceptable to the Nuclear  Regulatory  Commission (NRC) under which
the site would be maintained over a period of  approximately  60 years in such a
manner as to allow for  subsequent  decontamination  that  permits  release  for
unrestricted use.

       The Company's method of funding  decommissioning  costs is referred to as
COMReP (Cost of Money Reduction Plan).  Under this plan, funds collected through
rates ($3.2 million in each of 2000,  1999 and 1998) are used to pay premiums on
insurance policies on the lives of certain Company personnel. The Company is the
beneficiary of these policies. Through these insurance contracts, the Company is
able to take advantage of income tax benefits and accrue earnings on the fund on
a tax-deferred  basis.  Amounts for  decommissioning  collected through electric
rates,  insurance  proceeds,  and  interest  on  proceeds,  less  expenses,  are
transferred  by the Company to an  external  trust fund in  compliance  with the
financial  assurance  requirements of the NRC.  Management intends for the fund,
including  earnings  thereon,  to  provide  for  all  eventual   decommissioning
expenditures  on an  after-tax  basis.  The Company  records its  liability  for
decommissioning costs in deferred credits.

       In addition  to the above,  pursuant to the  National  Energy  Policy Act
passed by  Congress  in 1992 and the  requirements  of the DOE,  the Company has
recorded a liability for its estimated  share of the DOE's  decontamination  and
decommissioning  obligation.  The  liability,   approximately  $2.8  million  at
December 31, 2000,  has been included in "Long-Term  Debt,  net." The Company is
recovering  the cost  associated  with  this  liability  through  the fuel  cost
component  of its  rates;  accordingly,  this  amount has been  deferred  and is
included in "Deferred Debits - Other."

I.     Income Taxes

       The Company is included in the consolidated  federal income tax return of
SCANA Corporation.  Under a joint consolidated income tax allocation  agreement,
each subsidiary's  current and deferred tax expense is computed on a stand-alone
basis.  Deferred tax assets and  liabilities are recorded for the tax effects of
all significant  temporary  differences  between the book basis and tax basis of
assets and liabilities at currently  enacted tax rates.  Deferred tax assets and
liabilities are adjusted for changes in such rates through charges or credits to
regulatory  assets or liabilities if they are expected to be recovered  from, or
passed through to, customers;  otherwise, they are charged or credited to income
tax expense.

J.   Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt

     Long-term  debt  premium,  discount  and  expense  are being  amortized  as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues.  Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.

K.    Environmental

     The Company maintains an environmental  assessment  program to identify and
assess  current and former  operations  sites that could  require  environmental
cleanup.  As  site  assessments  are  initiated,   estimates  are  made  of  the
expenditures,  if any, deemed  necessary to investigate and remediate each site.
These  estimates  are  refined  as  additional  information  becomes  available;
therefore,  actual  expenditures  could differ  significantly  from the original
estimates.  Amounts  estimated  and  accrued  to date for site  assessments  and
cleanup relate primarily to regulated operations.  Such amounts are deferred and
amortized with recovery  provided  through rates. The Company also has recovered
portions of its  environmental  liabilities  through  settlements  with  various
insurance  carriers,  including all amounts previously deferred for its electric
operations.  The Company expects to recover all deferred  amounts related to its
gas  operations by December 2005.  Deferred  amounts,  net of amounts  recovered
through rates and insurance settlements, totaled $20.2 million and $23.7 million
at December 31, 2000 and 1999, respectively. The deferral includes the estimated
costs associated with the matters discussed in Note 12C.

L.     Fuel Inventories

       Nuclear  fuel and fossil fuel  inventories  and sulfur  dioxide  emission
allowances  are purchased  and financed by Fuel Company  under a contract  which
requires  the  Company to  reimburse  Fuel  Company  for all costs and  expenses
relating to the ownership and financing of fuel  inventories  and sulfur dioxide
emission allowances.  Accordingly, such fuel inventories and emission allowances
and   fuel-related   assets  and  liabilities  are  included  in  the  Company's
consolidated financial statements. (See Note 6.)

M.     Temporary Cash Investments

       The  Company  considers   temporary  cash  investments   having  original
maturities  of  three  months  or less to be cash  equivalents.  Temporary  cash
investments  are  generally in the form of  commercial  paper,  certificates  of
deposit and repurchase agreements.

 N.    Recently Issued Accounting Standard and Bulletin

In June 1998 the Financial  Accounting  Standards  Board (FASB) issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." In June 2000 the
FASB issued SFAS 138, which amends certain  provisions of SFAS 133 to expand the
normal purchase and sale exemption for supply contracts and to redefine interest
rate  risk to  reduce  sources  of  ineffectiveness,  among  other  things.  The
Company's  adoption of SFAS 133,  as amended,  on January 1, 2001 did not have a
material impact on the Company's results of operations,  cash flows or financial
position.

In December 1999 Staff  Accounting  Bulletin No. 101,  "Revenue  Recognition  in
Financial  Statements"  was issued by the  Securities  and  Exchange  Commission
(SEC),  and  provides  the SEC  staff's  views in  applying  generally  accepted
accounting  principles to selected  revenue  recognition  issues.  The Company's
adoption  of this  bulletin  in the fourth  quarter of 2000 had no impact on its
results of operations, cash flows or financial position.

O.        Reclassifications

       Certain amounts from prior periods have been reclassified to conform with
the presentation adopted for 2000.

P.     Use of Estimates

       The  preparation  of financial  statements in conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.

2.      Cumulative Effect of Accounting Change

        Effective  January 1, 2000 the Company  changed its method of accounting
for operating revenues from cycle billing to full accrual. The cumulative effect
of this change was $22 million,  net of tax.  Accruing  unbilled  revenues  more
closely matches revenues and expenses. Unbilled revenues represent the estimated
amount  customers will be charged for service  rendered but not yet billed as of
the end of the accounting period.

        If this method had been  applied  retroactively,  net income  would have
been $191  million and $220  million for the years ended  December  31, 1999 and
1998, respectively,  compared to $189 million and $227 million, respectively, as
reported.


<PAGE>




3.       RATE AND OTHER REGULATORY MATTERS

        A. On July 20,  2000 the PSC  issued an order  approving  the  Company's
request for an out-of-period adjustment to increase the cost of gas component of
its rates for natural gas service  from 54.334  cents per therm to 68.835  cents
per therm, effective with the first billing cycle in August 2000. As part of its
regularly  scheduled  annual  review of gas  costs,  the PSC  issued an order on
November 9, 2000 which  further  increased  the cost of gas  component to 78.151
cents per therm,  effective  with the first billing  cycle in November  2000. On
December 21, 2000 the PSC issued an order  approving the  Company's  request for
another out-of-period adjustment to increase the cost of gas component to 99.340
cents per therm, effective with the first billing cycle in January 2001.

        B. On July 5, 2000 the PSC approved the  Company's  request to implement
lower  depreciation  rates for its gas operations.  The new rates were effective
retroactively  to  January  1,  2000  and  resulted  in a  reduction  in  annual
depreciation expense of approximately $2.9 million.

       C. On September 14, 1999 the PSC approved an accelerated capital recovery
plan for the  Company's  Cope  Generating  Station.  The  plan  was  implemented
beginning  January  1,  2000  for a  three-year  period.  The  PSC  approved  an
accelerated  capital  recovery  methodology  wherein the  Company  may  increase
depreciation of its Cope  Generating  Station in excess of amounts that would be
recorded based upon currently  approved  depreciation  rates.  The amount of the
accelerated depreciation will be determined by the Company based on the level of
revenues and operating expenses,  not to exceed $36 million annually without the
approval of the PSC. Any unused portion of the $36 million in any given year may
be carried  forward for possible use in the  following  year. As of December 31,
2000 no accelerated  depreciation  has been recorded.  The  accelerated  capital
recovery plan will be accomplished through existing customer rates.

       D. On December 11, 1998 the PSC issued an order  requiring the Company to
reduce retail electric rates on a prospective  basis.  The PSC acted in response
to the Company  reporting that it earned a 13.04 percent return on common equity
for its retail  electric  operations for the 12 months ended September 30, 1998.
This return on common equity  exceeded the Company's  authorized  return of 12.0
percent by 1.04 percent, or $22.7 million,  primarily as a result of record heat
experienced during the summer. The order required prospective rate reductions on
a per kilowatt-hour  basis, based on actual retail sales for the 12 months ended
September 30, 1998. On January 12, 1999 the PSC denied the Company's  motion for
reconsideration,  ruled that no further rate action was required, and reaffirmed
the Company's  authorized return on equity of 12.0 percent.  The rate reductions
were placed into effect with the first billing cycle of January 1999.

       E. On  January 9, 1996 the PSC issued an order  granting  the  Company an
increase in retail electric rates which were fully  implemented by January 1997.
The PSC  authorized  a return on common  equity  of 12.0  percent.  The PSC also
approved  establishment  of a Storm Damage Reserve Account capped at $50 million
to be collected  through  rates over a ten-year  period.  Additionally,  the PSC
approved accelerated recovery of a significant portion of the Company's electric
regulatory  assets  (excluding  deferred  income tax assets)  and the  remaining
transition obligation for postretirement benefits other than pensions,  changing
the  amortization  periods to allow  recovery  by the end of the year 2000.  The
Company's request to shift, for rate-making purposes, approximately $257 million
of depreciation  reserves from  transmission and distribution  assets to nuclear
production  assets  was also  approved.  The  Consumer  Advocate  and two  other
intervenors appealed certain issues in the order initially to the Circuit Court,
which affirmed the PSC's decisions,  and subsequently,  to the Supreme Court. In
March 1998 the  Company,  the PSC,  the  Consumer  Advocate and one of the other
intervenors  reached an agreement that provided for the reversal of the shift in
depreciation  reserves and the dismissal of the appeal of all other issues.  The
PSC also  authorized  the  Company  to adjust  depreciation  rates that had been
approved in the 1996 rate order for its electric transmission,  distribution and
nuclear  production  properties  to  eliminate  the  effect of the  depreciation
reserve shift and to  retroactively  apply such  depreciation  rates to February
1996. As a result, a one-time reduction in depreciation  expense of $9.8 million
was recorded in March 1998. The agreement does not affect retail electric rates.
The FERC had previously rejected the transfer of depreciation reserves for rates
subject to its  jurisdiction.  In September  1998 the Supreme Court affirmed the
Circuit Court's rulings on the issues contested by the remaining intervenor.

       F. In 1994 the PSC issued an order  approving  the  Company's  request to
recover  through  a  billing  surcharge  to  its  gas  customers  the  costs  of
environmental cleanup at the sites of former manufactured gas plants (MGPs). The
billing  surcharge is subject to annual  review and provides for the recovery of
substantially  all actual and projected  site  assessment  and cleanup costs and
environmental  claims  settlements  for the  Company's gas  operations  that had
previously  been  deferred.  In November 2000, as a result of the annual review,
the PSC approved  the  Company's  request to maintain  the billing  surcharge at
$.011 per therm to provide for the  recovery of the  remaining  balance of $20.1
million.

       G. In  September  1992 the PSC  issued an order  granting  the  Company's
request  for a $.25  increase  in transit  fares from $.50 to $.75 in  Columbia,
South  Carolina;  however,  the PSC also  required  $.40  fares  for low  income
customers  and denied the  Company's  request to reduce the number of routes and
frequency of service. The new rates were placed into effect in October 1992. The
Company appealed the PSC's order to the Circuit Court, which in May 1995 ordered
the case back to the PSC for reconsideration of several issues including the low
income rider  program,  routing  changes,  and the $.75 fare.  The Supreme Court
declined to review an appeal of the Circuit  Court  decision and  dismissed  the
case. The PSC and other intervenors filed another Petition for  Reconsideration,
which the Supreme  Court  denied.  The PSC and other  intervenors  filed another
appeal to the Circuit Court which the Circuit Court denied in an order dated May
9, 1996.  In this  order,  the  Circuit  Court  upheld its  previous  orders and
remanded them to the PSC. During August 1996 the PSC heard oral arguments on the
orders on remand from the Circuit Court. On September 30, 1996 the PSC issued an
order  affirming  its  previous  orders  and denied the  Company's  request  for
reconsideration. In response to an appeal of the PSC's order by the Company, the
Circuit Court issued an order on May 25, 2000,  which remanded the matter to the
PSC for review of the Company's  original  application  and request to terminate
the low  income  rider  fare.  On  September  27,  2000 the PSC  issued an order
granting the relief requested by the Company. On September 29, 2000 the Consumer
Advocate  filed a motion  with the PSC for a stay of this  order,  to which  the
Company  filed a  response.  On October 3, 2000 the PSC  accepted  the  Consumer
Advocate's  motion and issued a stay of its order.  The  Consumer  Advocate  and
other  intervenors  have petitioned the Circuit Court for judicial review of the
PSC's order granting relief. Action by the Circuit Court is pending.

4.     EMPLOYEE BENEFIT PLANS

       The  Company  participates  in SCANA's  noncontributory  defined  benefit
pension plan, which covers substantially all permanent employees. SCANA's policy
has been to fund the plan to the  extent  permitted  by the  applicable  Federal
income tax regulations as determined by an independent actuary.

         Effective July 1, 2000,  SCANA's  pension plan was amended to provide a
cash balance formula. With certain exceptions,  employees were allowed to either
remain under the final  average pay formula or elect the cash  balance  formula.
Under the final  average pay formula,  benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment.  Under the cash balance formula,  the monthly benefit
earned  under the final  average pay formula at July 1, 2000 was  converted to a
lump sum amount for each  employee  and  increased  by  transition  credits  for
eligible  employees.  Under the cash balance  formula,  benefits based upon this
opening balance  increase going forward as a result of compensation  credits and
interest credits.  The effect of this plan amendment was to reduce the Company's
net  periodic   benefit   income  for  the  year  ended  December  31,  2000  by
approximately $3.4 million.

         In addition to pension benefits,  the Company provides certain unfunded
health  care and life  insurance  benefits  to  active  and  retired  employees.
Retirees  share in a portion of their  medical care cost.  The Company  provides
life insurance  benefits to retirees at no charge.  The costs of  postretirement
benefits other than pensions are accrued  during the years the employees  render
the services necessary to be eligible for the applicable benefits. Additionally,
to accelerate  the  amortization  of the  remaining  transition  obligation  for
postretirement  benefits  other than  pensions,  as  authorized  by the PSC, the
Company  expensed  approximately  $0.7  million and $15.7  million for the years
ended December 31, 1999 and 1998, respectively. (See Note 3E.)

         Effective July 1, 2000, PSNC's pension and postretirement benefit plans
were merged with SCANA's plans. At the time of the merger of the plans, PSNC had
recorded  a  prepaid   pension  cost  of   approximately   $9.0  million  and  a
postretirement  welfare plan  obligation  of  approximately  $9.1 million in its
consolidated balance sheet.


<PAGE>



         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>

Components of Net Periodic Benefit Cost

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

Millions of dollars                 2000          1999          1998              2000           1999        1998
--------------------------------- ---------- --------------- ------------ -- ---------------- ------------ ---------

<S>                                   <C>        <C>             <C>              <C>             <C>         <C>
Service Cost                          $8.3       $10.0           $8.3             $2.7            $3.0        $2.6
Interest Cost                         33.5         27.9          25.9             10.2              9.5        9.4
Expected return on assets            (76.6)       (65.5)        (59.3)             n/a              n/a        n/a
Prior service cost amortization        3.0          1.1            1.1             0.8              0.7        0.7
Actuarial (gain) loss                (12.2)        (8.6)          (9.6)              -              1.2        1.0
Transition amount amortization         0.8           0.8           0.8             0.8              1.7       19.1
Special termination benefit cost          -          5.5             -               -              1.0          -
Amount attributable to

   Company affiliates                  1.7           1.1           0.3               (1.6)         (0.9)    (0.7)
================================= ========== =============== ============ == ================ ============ =========
Net periodic benefit (income)
cost                               $(41.5)      $(27.7)        $(32.5)            $12.9          $16.2      $32.1
================================= ========== =============== ============ == ================ ============ =========

Weighted-Average Assumptions

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

 As of December 31                   2000          1999         1998              2000           1999        1998
--------------------------------- ------------ ------------- ------------ -- ---------------- ------------ ---------

<S>                                  <C>           <C>          <C>               <C>            <C>         <C>
Discount rate                        8.0%          8.0%         7.0%              8.0%           8.0%        7.0%
Expected return on plan assets       9.5%          9.5%         9.5%               n/a            n/a        n/a
Rate of compensation increase        4.0%          4.0%         4.0%              4.0%           4.0%        4.0%


Changes in Benefit Obligation

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

Millions of dollars                    2000            1999                2000                1999
--------------------------------- ---------------- -------------- -- ----------------- ---------------------
--------------------------------- ---------------- -------------- -- ----------------- ---------------------

<S>                         <C>       <C>             <C>                 <C>                 <C>
Benefit obligation, January 1         $362.3          $389.3              $129.8              $137.0
Service cost                               8.3           10.0                 2.7                 3.0
Interest cost                            33.5            27.9                10.2                 9.5
Plan participants' contributions           0.1             0.1                0.5                 0.5
Plan amendment                           65.4                -                0.9                    -
Actuarial (gain) loss                      1.6          (51.6)               (7.8)              (14.5)
Acquisition/merger of plans              39.8                -               11.2                    -
Benefits paid                           (31.7)          (18.9)               (8.5)               (6.7)
Special termination benefit cost             -             5.5                   -                1.0
================================= ================ ============== == ================= =====================
Benefit obligation, December 31       $479.3          $362.3              $139.0              $129.8
================================= ================ ============== == ================= =====================



<PAGE>




Change in Plan Assets

                                                                   Retirement Benefits

------------------------------------------------- ---------------------------- --------------------------
Millions of dollars                                          2000                        1999
------------------------------------------------- ---------------------------- --------------------------

<S>                                 <C>                     <C>                         <C>
Fair value of plan, assets, January 1                       $783.0                      $698.8
Actual return on plan assets                                   96.7                       103.0
Company contribution                                               -                           -
Plan participants' contributions                                 0.1                         0.1
Acquisition/merger of plans                                    46.2                            -
Benefits paid                                                 (31.7)                      (18.9)
------------------------------------------------- ---------------------------- --------------------------
Fair value of  plan assets, December 31                     $894.3                      $783.0
================================================= ============================ ==========================


Funded Status of Plans

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

Millions of dollars                           2000          1999                  2000            1999
------------------------------------------ ------------ -------------- ---- --------------- -----------------

<S>                     <C>                   <C>            <C>               <C>              <C>
Funded status, December 31                    $415.0         $420.7            $(139.0)         $(129.8)
Unrecognized actuarial (gain) loss           (297.6)         (294.0)               13.0             18.8
Unrecognized prior service cost                 73.7           11.4                 4.5              4.3
Unrecognized net transition obligation           4.8             5.6                8.3              9.1
------------------------------------------ ------------ -------------- ---- --------------- -----------------
Net asset (liability) recognized in
  Consolidated Balance Sheet                 $195.9         $143.7             $(113.2)          $(97.6)
========================================== ============ ============== ==== =============== =================
</TABLE>


Health Care Trends

The determination of net periodic other postretirement  benefit cost is based on
the following assumptions:

                                                2000       1999       1998
------------------------------------------ ---------- ---------- ----------

Health care cost trend rate                     7.5%       8.0%       8.5%
Ultimate health care cost trend rate            5.5%       5.5%       5.0%
Year achieved                                   2005       2005       2005

The effect of a one-percentage-point  increase or decrease in the assumed health
care  cost  trend  rates on the  aggregate  of the  service  and  interest  cost
components  of net  periodic  postretirement  health care  benefit  cost and the
accumulated other postretirement benefit obligation for health care benefits are
as follows:

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

Effect on health care cost                      $0.2              $(0.3)
Effect on postretirement obligation               2.9              (3.4)



<PAGE>



5.      LONG-TERM DEBT

     The  annual  amounts  of  long-term   debt   maturities  and  sinking  fund
requirements for the years 2001 through 2005 are summarized as follows:

 ----------------- ----------------- ------------------ -----------------
       Year             Amount             Year              Amount
 ----------------- ----------------- ------------------ -----------------
                          (Millions of Dollars)

       2001               $27.6            2004              $123.9
       2002                27.6            2005                173.9
       2003              129.8
 ----------------- ----------------- ------------------ -----------------

       Approximately  $23.5 million of the portion of long-term  debt payable in
2001 may be satisfied by either  deposit and  cancellation  of bonds issued upon
the basis of property  additions or bond  retirement  credits,  or by deposit of
cash with the Trustee.

       On August 7, 1996 the City of Charleston  executed  30-year  electric and
gas franchise  agreements with the Company.  In  consideration  for the electric
franchise agreement, the Company is paying the City $25 million over seven years
(1996-2002)  and  has  donated  to the  City  the  existing  transit  assets  in
Charleston.  The $25  million  is  included  in  electric  plant-in-service.  In
settlement  of  environmental  claims the City may have had  against the Company
involving the Calhoun Park area, where the Company and its predecessor companies
operated a MGP until the 1960's,  the Company  paid the City $26 million  over a
four-year period (1996-1999).

       The  Company  has  three-year  revolving  lines of  credit  totaling  $75
million,  in addition  to other  lines of credit,  that  provide  liquidity  for
issuance of commercial  paper.  The three-year  lines of credit provide  back-up
liquidity when commercial  paper  outstanding is in excess of $175 million.  The
long-term nature of the lines of credit allow commercial paper in excess of $175
million to be  classified as long-term  debt.  The  Company's  commercial  paper
outstanding  totaled  $117.5 million and $143.1 million at December 31, 2000 and
1999,  at weighted  average  interest  rates of 6.59  percent and 6.63  percent,
respectively.

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

6.     FUEL FINANCINGS

       Nuclear  and  fossil  fuel   inventories  and  sulfur  dioxide   emission
allowances  are  financed  through the  issuance by Fuel  Company of  short-term
commercial  paper.  These  short-term  borrowings  are  supported  by a  364-day
revolving credit agreement which expires December 19, 2001. 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.

     Commercial paper outstanding totaled $70.2 million at December 31, 2000 and
1999 at  weighted  average  interest  rates of 6.59  percent  and 6.44  percent,
respectively.

7.   SHORT-TERM BORROWINGS

       The Company pays fees to banks as compensation for its committed lines of
credit.  Commercial paper borrowings are for 270 days or less.  Details of lines
of credit  (including  uncommitted  lines of credit) and short-term  borrowings,
excluding  amounts  classified as long-term  (Note 5 ), at December 31, 2000 and
1999, are as follows:

Millions of dollars                               2000             1999
------------------------------------------------------------- ---------------


Authorized lines of credit at year-end           $375.0       $410.0

Unused lines of credit at year-end               $375.0       $410.0
Short-term borrowings outstanding at year-end:
      Commercial paper                           $187.7       $213.3
      Weighted average interest rate               6.59%        6.63%

8.       RETAINED EARNINGS

       The Restated  Articles of  Incorporation of the Company and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that, under
certain  circumstances,  could  limit the  payment of cash  dividends  on common
stock. In addition,  with respect to hydroelectric  projects,  the Federal Power
Act requires the  appropriation of a portion of certain earnings  therefrom.  At
December  31,  2000  approximately  $32.7  million  of  retained  earnings  were
restricted by this requirement as to payment of cash dividends on common stock.

9.     PREFERRED STOCK

       The call premium of the respective  series of preferred  stock in no case
exceeds the amount of the annual dividend.

     Retirements  under  sinking  fund  requirements  are  at  par  values.  The
aggregate  annual  amount of  purchase  fund or sinking  fund  requirements  for
preferred stock for the years 2001 through 2005 is $2.8 million.

       The  changes in "Total  Preferred  Stock  (Subject to purchase or sinking
funds)" during 2000, 1999 and 1998 are summarized as follows:

                                       Number of Shares  Millions of Dollars
-------------------------------------------------------- -----------------------
Balance at December 31, 1997               251,094               $12.5
   Shares Redeemed - $50 par value          (11,042)               (0.5)
-------------------------------------------------------- -----------------------
Balance at December 31, 1998               240,052                 12.0
   Shares Redeemed -  $50 par value          (8,565)               (0.4)
-------------------------------------------------------- -----------------------
Balance at December 31, 1999               231,487                 11.6
   Shares Redeemed  - $50 par value         (11,200)               (0.6)
-------------------------------------------------------- -----------------------
Balance at December 31, 2000               220,287               $11.0
======================================================== =======================

       On  October  28,  1997  SCE&G  Trust  I  (the  "Trust"),  a  wholly-owned
subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55 percent
Trust Preferred Securities,  Series A (the "Preferred Securities").  The Company
owns all of the Common  Securities of the Trust (the "Common  Securities").  The
Preferred   Securities  and  the  Common  Securities  (the  "Trust  Securities")
represent undivided  beneficial  ownership interests in the assets of the Trust.
The Trust exists for the sole purpose of issuing the Trust  Securities and using
the  proceeds  thereof to  purchase  from the Company  its 7.55  percent  Junior
Subordinated  Debentures  due September 30, 2027. The sole asset of the Trust is
$50.0 million of Junior Subordinated Debentures of the Company.  Accordingly, no
financial statements of the Trust are presented. The Company's obligations under
the  Guarantee   Agreement   entered  into  in  connection  with  the  Preferred
Securities,  when taken together with the Company's  obligation to make interest
and other payments on the Junior Subordinated Debentures issued to the Trust and
the  Company's  obligations  under the  Indenture  pursuant  to which the Junior
Subordinated Debentures were issued, provides a full and unconditional guarantee
by the  Company  of the  Trust's  obligations  under the  Preferred  Securities.
Proceeds were used to redeem preferred stock of the Company.

       The preferred  securities of the Trust are redeemable only in conjunction
with the redemption of the related 7.55 percent Junior Subordinated  Debentures.
The Junior Subordinated  Debentures will mature on September 30, 2027 and may be
redeemed,  in whole or in part,  at any time on or after  September  30, 2002 or
upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received
from  counsel   experienced   in  such  matters  that  there  is  more  than  an
insubstantial  risk that:  (1) the Trust is or will be subject to Federal income
tax,  with  respect to income  received  or  accrued on the Junior  Subordinated
Debentures,  (2)  interest  payable by the  Company  on the Junior  Subordinated
Debentures  will not be  deductible,  in whole or in part,  by the  Company  for
Federal income tax purposes,  or (3) the Trust will be subject to more than a de
minimis amount of other taxes, duties, or other governmental charges.

       Upon the redemption of the Junior Subordinated  Debentures,  payment will
simultaneously  be applied to redeem  Preferred  Securities  having an aggregate
liquidation  amount  equal  to the  aggregate  principal  amount  of the  Junior
Subordinated  Debentures.  The Preferred  Securities  are  redeemable at $25 per
preferred security plus accrued distributions.



<PAGE>



10.    INCOME TAXES

       Total income tax expense  attributable to income before cumulative effect
of accounting change for 2000, 1999 and 1998 is as follows:
<TABLE>

Millions of dollars                                2000            1999              1998
------------------------------------------------------------ ----------------- -----------------
Current taxes:
<S>                                              <C>                <C>              <C>
      Federal                                    $78.4              $91.3            $116.1
      State                                         7.8                 0.3                2.1
------------------------------------------------------------ ----------------- -----------------
------------------------------------------------------------ ----------------- -----------------
            Total current taxes                    86.2               91.6             118.2
------------------------------------------------------------ ----------------- -----------------
------------------------------------------------------------ ----------------- -----------------
Deferred taxes, net:
      Federal                                      31.8                 7.7                1.8
      State                                         5.2                 1.4                2.0
------------------------------------------------------------ ----------------- -----------------
------------------------------------------------------------ ----------------- -----------------
            Total deferred taxes                   37.0                 9.1                3.8
------------------------------------------------------------ ----------------- -----------------
------------------------------------------------------------ ----------------- -----------------
Investment tax credits:
      Deferred - State                              5.0               13.4               14.3
      Amortization of amounts deferred - State     (1.3)               (1.2)              (0.9)
      Amortization of amounts deferred - Federal   (3.2)               (3.2)              (3.2)
------------------------------------------------------------ ----------------- -----------------
            Total investment tax credits            0.5                 9.0          10.2
------------------------------------------------------------ ----------------- -----------------
Non-conventional fuel tax credits:
      Deferred - Federal                            9.4               n/a             n/a
------------------------------------------------------------ ----------------- -----------------
            Total income tax expense             133.1            $109.7             $132.2
============================================================ ================= =================

    The difference  between actual income tax expense and the amount  calculated
from the  application  of the statutory  Federal  income tax rate (35% for 2000,
1999 and 1998) to pre-tax income before  cumulative  effect of accounting change
is reconciled as follows:


Millions of dollars                                                   2000              1999              1998
--------------------------------------------------------------- ----------------- ----------------- -----------------


<S>                                                                  <C>               <C>                <C>
Income before cumulative effect of accounting change                 $223.9            $181.8             $219.7
Total income tax expense:
   Charged to operating expense                                        123.8            103.1            127.9
   Charged to other items                                                 9.3              6.6              4.2
Preferred stock dividends                                                 7.4              7.4              7.5
--------------------------------------------------------------- ----------------- ----------------- -----------------
      Total pre-tax income                                           $364.4            $298.9             $359.3
=============================================================== ================= ================= =================
=============================================================== ================= ================= =================

Income taxes on above at statutory Federal income tax rate           $127.5           $104.6            $125.8
Increases (decreases) attributed to:
   State income taxes (less Federal income tax effect)                  10.9                9.0             11.4
   Amortization of Federal investment tax credits                       (3.2)              (3.2)             (3.2)
   Other differences, net                                               (2.1)              (0.7)             (1.8)
--------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
        Total income tax expense                                     $133.1           $109.7            $132.2
=============================================================== ================= ================= =================



<PAGE>




       The tax  effects of  significant  temporary  differences  comprising  the
Company's net deferred tax liability of $604.1  million at December 31, 2000 and
$544.8 million at December 31, 1999 (see Note 1I), are as follows:

Millions of dollars                                                                    2000              1999
--------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax assets:
<S>                                                                                     <C>                <C>
   Unamortized investment tax credits                                                   $57.3              $57.9
   Other postretirement benefits                                                         40.6                36.6
   Early retirement programs                                                             14.6                14.8
   Deferred compensation                                                                   8.6                 8.6
   Cycle billing                                                                             -               15.5
   Other                                                                                   7.7               11.1
--------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax assets                                                      128.8               144.5
--------------------------------------------------------------------------------- ---------------- ------------------

Deferred tax liabilities:
   Property, plant and equipment                                                        609.5              593.5
   Pension plan benefit income                                                           65.3                50.7
   Research and experimentation costs                                                    26.8                27.3
   Deferred fuel costs                                                                   18.5                  5.5
   Cycle billing                                                                           1.9               -
   Other                                                                                 10.9                12.3
--------------------------------------------------------------------------------- ---------------- ------------------
        Total deferred tax liabilities                                                  732.9              689.3
--------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability                                                            $604.1             $544.8
================================================================================= ================ ==================
</TABLE>

       The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of SCANA through 1995, has examined and proposed  adjustments
to SCANA's 1996 and 1997 Federal  returns,  and is currently  examining  SCANA's
Federal  returns for 1998 and 1999.  The Company  does not  anticipate  that any
adjustments  which might result from these  examinations will have a significant
impact on its results of operations, cash flows or financial position.

11.    FINANCIAL INSTRUMENTS

       The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2000 and 1999 are as follows:
<TABLE>

    Millions of dollars                                              2000                     1999
    -------------------------------------------------------- ---------------------- --------------------------
                                                                          Estimated                Estimated
                                                              Carrying      Fair       Carrying       Fair
                                                               Amount       Value       Amount       Value
    -------------------------------------------------------- ----------- ------------ ------------ -----------
    Assets:
<S>                                                               <C>         <C>          <C>         <C>
      Cash and temporary cash investments                         $60.2       $60.2        $78.4       $78.4

       Investments                                              6.4              6.4      4.7             4.7
    Liabilities:
      Short-term borrowings                                      187.7        187.7        213.3       213.3
      Long-term debt                                           1,294.1     1,331.6      1,248.6     1,232.7
      Preferred stock (subject to purchase or sinking
    funds)                                                         11.0          8.7        11.6          8.5
    -------------------------------------------------------- ----------- ------------ ------------ -----------
</TABLE>
  The information  presented herein is based on pertinent  information available
as of  December  31,  2000 and 1999.  Although  the  Company is not aware of any
factors that would significantly  affect the estimated fair value amounts,  such
financial instruments have not been comprehensively  revalued since December 31,
2000,  and the current  estimated fair value may differ  significantly  from the
estimated fair value at that date.



<PAGE>



       The  following  methods and  assumptions  were used to estimate  the fair
value of the above classes of financial instruments:

o            Cash and temporary cash  investments,  including  commercial paper,
             repurchase  agreements,  treasury  bills and  notes,  are valued at
             their carrying amount.

o            Fair values of  investments  and long-term debt are based on quoted
             market prices of the instruments or similar  instruments.  For debt
             instruments for which there are no quoted market prices  available,
             fair  values  are  based on net  present  value  calculations.  For
             investments  for which the fair value is not readily  determinable,
             fair value approximates cost.  Settlement of long-term debt may not
             be possible or may not be considered prudent.

o        Short-term borrowings are valued at their carrying amount.

o            The fair value of preferred  stock  (subject to purchase or sinking
             funds) is estimated on the basis of market prices.

o            Potential  taxes and other  expenses  that would be  incurred in an
             actual sale or settlement have not been taken into consideration.

12.  COMMITMENTS AND CONTINGENCIES:

A.      Lake Murray Dam Reinforcement

        On October 15, 1999 FERC notified the Company of its agreement  with the
Company's  plan to  reinforce  Lake Murray Dam in order to maintain  the lake in
case of an  extreme  earthquake.  The  Company  and FERC  have  been  discussing
possible  reinforcement  alternatives for the dam over the past several years as
part of the Company's ongoing  hydroelectric  operating license with FERC. Until
discussions  are  concluded,  it is not  possible  to  finalize  the cost of the
project;  however,  it is possible that the cost could range up to $250 million.
Although  any costs  incurred  by the Company  are  expected  to be  recoverable
through  electric rates,  the Company also is exploring  alternative  sources of
funding. The project is expected to be completed in 2004.

B.      Nuclear Insurance

        The  Price-Anderson   Indemnification   Act,  which  deals  with  public
liability for a nuclear incident,  currently establishes the liability limit for
third-party  claims  associated with any nuclear incident at $9.5 billion.  Each
reactor  licensee is currently  liable for up to $88.1 million per reactor owned
for each  nuclear  incident  occurring  at any  reactor  in the  United  States,
provided  that not more than $10 million of the  liability  per reactor would be
assessed per year.  The Company's  maximum  assessment,  based on its two-thirds
ownership of Summer Station,  would be approximately $58.7 million per incident,
but not more than $6.7 million per year.

       The Company  currently  maintains  policies  (for itself and on behalf of
Santee Cooper) with Nuclear  Electric  Insurance  Limited  (NEIL).  The policies
covering the nuclear  facility for property  damage,  excess property damage and
outage cost permit  assessments  under  certain  conditions  to cover  insurer's
losses.  Based on the  current  annual  premium,  the  Company's  portion of the
retroactive premium assessment would not exceed $8.1 million.

      To the extent that insurable claims for property damage,  decontamination,
repair and  replacement  and other  costs and  expenses  arising  from a nuclear
incident at Summer  Station  exceed the policy  limits of  insurance,  or to the
extent such insurance becomes  unavailable in the future, and to the extent that
the  Company's  rates would not recover  the cost of any  purchased  replacement
power,  the Company will retain the risk of loss as a self-insurer.  The Company
has no reason to anticipate a serious  nuclear  incident at Summer  Station.  If
such an incident were to occur,  it could have a material  adverse impact on the
Company's results of operations, cash flows and financial position.



<PAGE>



C.     Environmental

       In September 1992 the Environmental  Protection Agency (EPA) notified the
Company,  the City of Charleston and the Charleston  Housing  Authority of their
potential  liability for the  investigation and cleanup of the Calhoun Park area
site in Charleston, South Carolina. This site encompasses approximately 30 acres
and  includes  properties  which  were  locations  for  industrial   operations,
including  a  wood   preserving   (creosote)   plant,   one  of  the   Company's
decommissioned  manufactured gas plants (MGP),  properties owned by the National
Park Service and the City of Charleston,  and private  properties.  The site has
not been placed on the National Priorities List, but may be added in the future.
The Potentially Responsible Parties (PRPs) negotiated an administrative order by
consent  for the  conduct  of a Remedial  Investigation/Feasibility  Study and a
corresponding  Scope of Work.  Field work began in  November  1993,  and the EPA
approved a Remedial  Investigation  Report in  February  1997 and a  Feasibility
Study Report in June 1998. In July 1998 the EPA approved the  Company's  Removal
Action Work Plan for soil  excavation.  The Company  completed  Phase One of the
Removal Action Work Plan in 1998 at a cost of approximately $1.5 million.  Phase
Two, which cost approximately $3.5 million, included excavation and installation
of several  permanent  barriers to mitigate  coal tar seepage.  On September 30,
1998 a Record of  Decision  was  issued  which  sets forth the EPA's view of the
extent of each  PRP's  responsibility  for site  contamination  and the level to
which the site must be  remediated.  The  Company  estimates  that the Record of
Decision  will  result  in  costs  of  approximately  $13.3  million,  of  which
approximately  $2  million  remains.  On  January  13,  1999  the EPA  issued  a
Unilateral   Administrative  Order  for  Remedial  Design  and  Remedial  Action
directing  the  Company  to design and carry out a plan of  remediation  for the
Calhoun Park site. The Company  submitted a  Comprehensive  Remedial Design Work
Plan  (RDWP) on December  17, 1999 and  proceeded  with  implementation  pending
agency  approval.  The  RDWP  was  approved  by the  EPA in July  2000,  and its
implementation continues.

          In October  1996 the City of  Charleston  and the Company  settled all
environmental  claims the City may have had against the  Company  involving  the
Calhoun  Park area for a payment of $26 million over four years  (1996-1999)  by
the Company to the City. The Company is recovering the amount of the settlement,
which does not encompass site assessment and cleanup costs, through rates in the
same  manner as other  amounts  accrued  for site  assessments  and  cleanup  as
discussed  above.  As  part  of  the  environmental   settlement,   the  Company
constructed an 1,100 space parking garage on the Calhoun Park site (construction
was  completed  in April  2000)  and  transferred  the  facility  to the City in
exchange for a $16.5 million,  18-year municipal bond collateralized by revenues
from, and a mortgage on, the parking garage.

         The Company  owns three other  decommissioned  MGP sites which  contain
residues  of  by-product  chemicals.  For the  site  located  in  Sumter,  South
Carolina,  effective  September  15, 1998,  the Company  entered into a Remedial
Action Plan  Contract  with DHEC pursuant to which it agreed to undertake a full
site   investigation   and  remediation   under  the  oversight  of  DHEC.  Site
investigation and characterization  are proceeding  according to schedule.  Upon
selection and  successful  implementation  of a site remedy,  DHEC will give the
Company a  Certificate  of  Completion,  and a covenant not to sue. For the site
located in Florence, South Carolina, the Company entered into a similar Remedial
Action Plan  Contract  with DHEC  effective  September  5, 2000.  The Company is
continuing to investigate the remaining site in Columbia,  and is monitoring the
nature and extent of residual contamination.

D.     Franchise Agreement

       See Note 5 for a discussion of the electric  franchise  agreement between
SCE&G and the City of Charleston.

E.     Claims and Litigation

       SCANA and  Westvaco  each own a 50 percent  interest  in Cogen  South LLC
(Cogen).  Cogen was  formed to build and  operate  a  cogeneration  facility  at
Westvaco's Kraft Division Paper Mill in North  Charleston,  South Carolina.  The
facility began operations in March 1999. On September 10, 1998 the contractor in
charge of  construction  filed  suit in South  Carolina  Circuit  Court  seeking
approximately  $52 million from Cogen,  alleging  that it incurred  construction
cost  overruns  relating  to the  facility  and that the  construction  contract
provides  for  recovery of these  costs.  In addition  to Cogen,  Westvaco,  the
Company and SCANA were also named as defendants in the suit. The Company and the
other  defendants  believe  the  suit  is  without  merit  and are  mounting  an
appropriate  defense.  The Company does not believe that the  resolution of this
issue will have a material  impact on its results of  operations,  cash flows or
financial position.

       The  Company  is also  engaged  in various  other  claims and  litigation
incidental  to its business  operations  which  management  anticipates  will be
resolved without material loss to the Company.

13.      SEGMENT OF BUSINESS INFORMATION

         The  Company's  reportable  segments,  based on combined  revenues from
external and internal sources, 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 PSC and
the 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 31 counties in South Carolina covering
approximately 21,000 square miles.

         The  Company's   reportable   segments   share  a  similar   regulatory
environment and, in some cases,  overlapping  service areas.  However,  Electric
Operation's  product  differs  from Gas  Distribution,  as does  its  generation
process and method of distribution.

Disclosure of Reportable Segments
<TABLE>

Millions of dollars
-------------------------------- ------------- -------------- ----------- ---------------- ------------------
                                   Electric         Gas          All       Adjustments/      Consolidated
             2000                 Operations   Distribution     Other      Eliminations          Total
-------------------------------- ------------- -------------- ----------- ---------------- ------------------

<S>                                 <C>            <C>             <C>          <C>             <C>
External Customer Revenue           $1,344         $325            $1           $(1)            $1,669
Intersegment Revenue                    218            2            -          (220)                   -
Operating Income (Loss)                430            31            -             (4)               457
Interest Expense                          5          n/a            4            96                 105
Depreciation & Amortization            147           11             -              -                158
Assets                               4,655          416             -          (407)             4,664
Expenditures for Assets                227           19             -            32                278
Deferred Tax Assets                       -          n/a            -              -                  -
-------------------------------- ------------- -------------- ----------- ---------------- ------------------

                                  Electric         Gas           All       Adjustments/      Consolidated
             1999                Operations    Distribution     Other      Eliminations          Total
-------------------------------- ------------ --------------- ----------- ---------------- ------------------

<S>                                  <C>           <C>                <C>       <C>                 <C>
External Customer Revenue            $1,226        $239               $2        $(2)                $1,465

Intersegment Revenue             203                   2      -                (205)       -

Operating Income (Loss)          376                 22       -                   (5)                    393

Interest Expense                 5                  n/a                4         93                      102

Depreciation & Amortization      140                 13                -           -                     153
Segment Assets                         4,452       399                 6       (453)                  4,404

Expenditures for Assets          198                 19       -                   16                     233

Deferred Tax Assets              2                 n/a                 -         14        16
-------------------------------- ------------ --------------- ----------- ---------------- ------------------



<PAGE>




                                  Electric         Gas           All       Adjustments/      Consolidated
             1998                Operations    Distribution     Other      Eliminations          Total
-------------------------------- ------------ --------------- ----------- ---------------- ------------------

<S>                                 <C>            <C>           <C>               <C>             <C>
External Customer Revenue           $1,220         $230          $ 2               $(2)            $1,450

Intersegment Revenue                     201           3           -             (204)     -
Operating Income (Loss)                  423          29           -                 (4)                448

Interest Expense                 4                   n/a           4                86                    94
Depreciation & Amortization              119         12            -                   -                131
Assets                                4,305        381             4            (444)                4,246
Expenditures for Assets                  186         19            -                48                  253

Deferred Tax Assets              1                  n/a            -                20                    21
-------------------------------- ------------ --------------- ----------- ---------------- ------------------
</TABLE>

         Management uses operating income to measure segment  profitability  for
regulated  operations.  Accordingly,  the  Company  does not  allocate  interest
charges or income tax expense (benefit) to its segments.  Similarly,  management
evaluates  utility  plant for its  segments.  Therefore,  the  Company  does not
allocate accumulated depreciation, common and non-utility plant, or deferred tax
assets to reportable segments. Interest income is not reported by segment and is
not material.

         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.  Adjustments to assets consist of various
reclassifications  made for external reporting purposes.  Segment assets include
utility plant only (excluding  accumulated  depreciation) for all segments. As a
result,  unallocated assets include accumulated depreciation,  offset in part by
common and non-utility plant and non-fixed assets for the segments.

         Adjustments  to  Interest  Expense  and  Deferred  Tax  Assets  include
primarily  the totals from the Company that are not  allocated to the  segments.
Interest Expense is also adjusted to eliminate  inter-segment charges.  Deferred
Tax Assets are also adjusted to remove the non-current portion of those assets.

14.      SUBSEQUENT EVENTS

       On January 24, 2001 the Company  issued $150 million First Mortgage Bonds
having an annual interest rate of 6.70 percent and maturing on February 1, 2001.

15.  QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>


Millions of Dollars, except per share amounts

------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
                                                          First        Second        Third       Fourth
2000                                                     Quarter      Quarter       Quarter      Quarter     Annual
------------------------------------------------------- ----------- ------------- ------------ ------------ ---------

<S>                                                        <C>          <C>          <C>          <C>        <C>
Total operating revenues                                   $395         $371         $448         $455       $1,669

Operating income                                          108(1)          96          155            98          457
Income before cumulative effect of accounting change         55           44           82            50         231
Cumulative effect of accounting change, net of taxes          22            -            -            -          22
Net income                                                    77          44           82           50          253
------------------------------------------------------- ----------- ------------- ------------ ------------ ---------

------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
                                                          First        Second        Third       Fourth
1999                                                     Quarter      Quarter       Quarter      Quarter     Annual
------------------------------------------------------- ----------- ------------- ------------ ------------ ---------

<S>                                                        <C>           <C>           <C>          <C>     <C>
Total operating revenues                                   $352          $338          $431         $344    $1,465

Operating income                                             99              80          148            66  393

Net income                                                   48              37   77                    27       189
------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
</TABLE>

(1)  Excludes  $30 million of income taxes  formerly  reported in first  quarter
operating income.

<PAGE>


















                             PUBLIC SERVICE COMPANY
                         OF NORTH CAROLINA, INCORPORATED








Item 7.       Management's Narrative Analysis of
                  Results of Operations.................................  109

Item 7A.      Quantitative Disclosures About Market Risk................  112

Item 8.       Financial Statements and Supplementary Data...............  113






Public Service Company of North Carolina,  Incorporated meets the conditions set
forth in  General  Instruction  I(1)(a)  and (b) of Form 10-K and  therefore  is
filing  this form with the  reduced  disclosure  format  allowed  under  General
Instruction I(2).

<PAGE>



ITEM 7.  MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS.


         Statements  included in this  narrative  analysis (or elsewhere in this
annual report) which are not  statements of historical  fact are intended to be,
and are hereby  identified  as,  forward-looking  statements for purposes of the
safe harbor  provided by Section 27A of the  Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended.  Readers are
cautioned  that such  forward-looking  statements  are not  guarantees of future
performance  and  involve a number of risks and  uncertainties,  and that actual
results could differ  materially  from those  indicated by such  forward-looking
statements.  Important  factors  that  could  cause  actual  results  to  differ
materially from those indicated by such forward-looking  statements include, but
are not limited to, the following:  (1) that the information is of a preliminary
nature and may be subject to further and/or  continuing  review and  adjustment,
(2) changes in the utility regulatory  environment,  (3) changes in the economy,
especially in PSNC's service territory, (4) the impact of competition from other
energy  suppliers,  (5)  growth  opportunities,  (6) the  results  of  financing
efforts,  (7) changes in PSNC's  accounting  policies,  (8) weather  conditions,
especially in areas served by PSNC, (9) inflation, (10) changes in environmental
regulations,  and (11) the other risks and uncertainties  described from time to
time in  PSNC's  periodic  reports  filed  with  the  SEC.  PSNC  disclaims  any
obligation to update any forward-looking statements.

         SCANA  acquired PSNC and PSNC's fiscal year was changed from  September
30 to December 31,  effective in 2000. The  accompanying  narrative  analysis is
presented in terms of a comparison of the twelve months ended  December 31, 2000
and 1999.  In  connection  with the  acquisition,  which was  accounted for as a
purchase,  the excess of the purchase price over the fair value of PSNC's assets
and  liabilities  was  recorded  as an  acquisition  adjustment  which  is being
amortized over a 35 year period. <TABLE>

                    Condensed Consolidated Income Statements
---------------------------------------------------- --------------------------------- ------------------ ---------------
                               Twelve Months Ended
                                                           December 31,                                      %
Millions of dollars                                    2000*            1999             Change           Change
---------------------------------------------------- ----------------- --------------- ------------------ ---------------

<S>                                                   <C>              <C>               <C>                 <C>
Operating Revenues                                    $546.8           $306.7            $240.1              78.3

Cost of Gas                                           (374.4)          (141.5)            (232.9)          164.6
---------------------------------------------------- ----------------- --------------- ------------------
Gross Margin                                            172.4            165.2                7.2             4.4
---------------------------------------------------- ----------------- --------------- ------------------
Operating Expenses:

   Operation and maintenance                             67.6           69.3             (1.7)             (2.5)

   Depreciation and amortization                         41.9           26.2                15.7             59.9

   Other taxes                                            6.4           12.9             (6.5)            (50.4)
---------------------------------------------------- ----------------- --------------- ------------------

      Total Operating Expenses                         115.9             108.4                7.5           6.9
---------------------------------------------------- ----------------- --------------- ------------------

Operating Income                                         56.5           56.8              (.3)             (0.5)

Other Income, net                                         8.2            6.6           1.6                 24.2

Interest Charges                                        19.6            18.3                  1.3           7.1
---------------------------------------------------- ----------------- --------------- ------------------
Income Before Income Taxes and

   Cumulative Effect of Accounting Change               45.1            45.1                    -            -

Income Taxes                                            23.9            19.3                 4.6           23.8
---------------------------------------------------- ----------------- --------------- ------------------
Income Before Cumulative Effect of

   Accounting  Change                                   21.2            25.8             (4.6)            (17.8)
Cumulative Effect of Accounting

   Change, net of taxes                                   6.6             -                  6.6             -
---------------------------------------------------- ----------------- --------------- ------------------

Net Income                                             $27.8             $25.8              $2.0            7.8
==================================================== ================= =============== ==================
*   Effective December 31, 1999, SCANA Public Service Company, L.L.C. (formerly Sonat Public Service Company, L. L.C.)
was consolidated with PSNC.

</TABLE>


<PAGE>




Earnings and Dividends

         Net income for the twelve  months ended  December 31, 2000 and 1999 was
as follows:

Millions of dollars                          2000              1999
----------------------------------------- ------------------ -----------------

Net income derived from:
   Continuing operations                    $21.2              $25.8
   Cumulative effect of accounting
    change, net of taxes                      6.6                 -
========================================= ================== =================
       Net income                           $27.8              $25.8
========================================= ================== =================

         Net income from  continuing  operations  decreased  approximately  $4.6
million,  primarily as a result of increased  amortization  expense arising from
the  amortization  of  the  utility  plant  acquisition  adjustment,  which  was
partially  offset by improved  margin and a decrease in other taxes. In 2000 the
cumulative  effect  of an  accounting  change  resulted  from the  recording  of
unbilled revenues (See Note 2 of Notes to Consolidated Financial Statements).

         The nature of PSNC's business is seasonal.  The quarters ending June 30
and September 30 are generally PSNC's least profitable quarters due to decreased
demand for natural gas related to lower space heating requirements.

         PSNC's  Board of  Directors  authorized  payment of dividends on common
stock held by SCANA as follows:

Declaration Date     Dividend Amount   Quarter Ended       Payment Date

February 22, 2000     $6.0 million     March 31, 2000      April 1, 2000
April 27, 2000        $5.0 million     June 30, 2000       July 1, 2000
August 16, 2000       $4.5 million     September 30, 2000  October 1, 2000
October 17, 2000      $3.5 million     December 31, 2000   January 1, 2001

Gas Distribution

         Gas distribution  sales margins (excluding the cumulative effect of the
change in accounting and  eliminating  the impact of franchise  taxes in 1999 as
described at Other Operating  Expenses) for the twelve months ended December 31,
2000 and 1999 were as follows:

Millions of dollars         2000         1999     Change       % Change
------------------------ ------------------------------------------------------

Gas operating revenue      $405.6       $300.4      $105.2         35.0%
Less:  Cost of gas         (237.4)      (141.4)      (96.0)       67.9%
======================== =====================================
Gross margin               $168.2       $159.0         $9.2         5.8%
======================== ======================================================

         The increase in margin for the year ended  December 31, 2000  primarily
resulted from customer growth.



<PAGE>



Energy Marketing

         Energy marketing is comprised of SCANA Public Service Company,  L.L.C.,
which became a wholly owned  subsidiary of PSNC effective  December 31, 1999 and
participates in nonregulated activities such as natural gas brokering and supply
services.   Energy  marketing  operating  revenues  and  net  income  (including
affiliated transactions) for the year ended December 31, 2000 was as follows:


         Millions of dollars
         -----------------------------------------------------------------------

           Operating  revenues                           $142.9
           Net income                                       2.0
         =======================================================================

Operation and Maintenance Expenses

         The $1.7 million  decrease in operation and  maintenance  expenses from
1999 reflects a net decrease in operating  costs arising from the acquisition of
PSNC by SCANA (see Note 3 of Notes to Consolidated Financial  Statements).  This
decrease was  partially  offset by the  consolidation  of SCANA  Public  Service
Company, L.L.C. in 2000.

Other Operating Expenses

         Depreciation and amortization  expense  increased  approximately  $15.7
million for the year ended  December  31, 2000 as compared to the same period in
1999  primarily  due  to  the  amortization  of the  utility  plant  acquisition
adjustment (see Note 3 of Notes to Consolidated Financial Statements).

         Other taxes  decreased for the year ended December 31, 2000 as compared
to the same period in 1999 primarily as a result of the elimination of franchise
taxes by the State of North Carolina effective August 1, 1999. The franchise tax
was replaced by an excise tax. Franchise taxes totaled $6.3 million in 1999, and
were included in PSNC's  billing rates and recorded as both  operating  revenues
and other  taxes.  The new excise tax is added to  customer  bills  based on the
volume of natural gas  consumed.  PSNC does not include the excise tax in either
operating  revenues  or  other  taxes , as this tax is a  pass-through  from the
customer to the State of North Carolina.

Other Income, net

         Other income increased for the year ended December 31, 2000 as compared
to the same period in 1999  primarily  due to a $1.4 million gain on the sale of
properties  during  the  fourth  quarter  2000 and an  increase  in income  from
subsidiary operations.

Interest Expense

         Interest  expense  increased  $1.3  million  over  1999 as a result  of
increased borrowings and increased weighted average interest rates on short-term
debt.

Income Taxes

         Income taxes increased for the year ended December 31, 2000 compared to
the corresponding  period for 1999,  primarily due to the  non-deductibility  of
amortization expense related to the acquisition adjustment.



<PAGE>



Capital Expansion Program

         PSNC's capital  expansion  program  includes the construction of lines,
systems  and  facilities  and the  purchase  of related  equipment.  PSNC's 2001
construction   budget  is   approximately   $58  million,   compared  to  actual
construction  expenditures  for  2000 of $39.1  million.  The  financing  of the
capital expansion program is expected to be funded through borrowings, including
advances from SCANA.

Competition

         Although  PSNC is the sole  distributor  of natural  gas in its service
area,  it faces  competition  from  suppliers  of alternate  fuels.  The primary
alternate fuels available to large commercial and industrial  customers are fuel
oil and propane.  The primary  competition to natural gas in the residential and
smaller commercial markets is electricity.

         The NCUC has  approved a rate  structure  that allows PSNC to negotiate
reduced rates in order to match the cost of alternate fuels to large  commercial
and  industrial  customers  and recover  the lost  margin from other  classes of
customers.  PSNC anticipates that the need to negotiate reduced rates with these
customers will continue.

         Electric  restructuring  efforts in North Carolina have been stalled by
developments  in California,  concerns over municipal  power  agencies' debt and
other  factors.   Legislation  or  regulatory   action  at  the  Federal  level,
particularly as part of a larger energy policy initiative,  may be considered in
2001.  PSNC is not able to predict  whether  any  restructuring  legislation  or
regulatory action will be enacted and, if it is, the impact it will have on PSNC
and the natural gas industry.


Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

         Interest rate risk - The table below provides  information about PSNC's
financial  instruments that are sensitive to changes in interest rates. For debt
obligations,  the table  presents  principal  cash  flows and  related  weighted
average interest rates by expected maturity dates. <TABLE>

    December 31, 2000                                                Expected Maturity Date
    (Millions of dollars)

                                                                                                                  Fair
    Liabilities                        2001      2002       2003       2004       2005     Thereafter    Total      Value
    -------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- ----------

      Long-Term Debt:
<S>              <C>                    <C>        <C>        <C>        <C>        <C>      <C>         <C>        <C>
      Fixed Rate ($)                    4.3        4.3        7.5        7.5        3.2      122.4       149.2      154.9

      Average Fixed Interest Rate       10.0%     10.0%      9.47%      9.47%      8.75%      7.50%       7.87%         -


    December 31, 1999                                                Expected Maturity Date
    (Millions of dollars)

                                                                                                                  Fair
    Liabilities                        2000      2001      2002      2003        2004     Thereafter    Total       Value
    -------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- ----------

      Long-Term Debt:
<S>              <C>                    <C>       <C>       <C>        <C>        <C>       <C>         <C>         <C>
      Fixed Rate ($)                    6.8       5.6       4.3        7.5        7.5       125.6       157.3       156.4
      Average Fixed Interest Rate       10.0%     10.0%     10.0%     9.47%       9.47%        7.53%       7.98%         -
</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.



<PAGE>



ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         INDEX TO CONSOLIDATED FINANCIAL
                        STATEMENTS AND SUPPLEMENTARY DATA

                                                                           Page

    Independent  Auditors' Reports........................................  114

    Consolidated Financial Statements:

    Consolidated Balance Sheets as of December 31, 2000 and 1999..........  116

   Consolidated Statements of Income and Retained Earnings for the
           Year Ended December 31, 2000, the Three Months Ended
           December 31, 1999 and the Fiscal Years Ended
           September 30, 1999 and 1998....................................  117

   Consolidated Statements of Cash Flows for the Year  Ended
          December 31, 2000, the Three Months Ended December 31, 1999 and
          the Fiscal Years Ended September 30, 1999 and 1998..............  118
   Consolidated Statements of Capitalization as of
     December 31, 2000 and 1999...........................................  119
   Notes to Consolidated Financial Statements.............................  120














<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,  2000 and  1999,  and the  related  Consolidated
Statements of Income and Retained  Earnings and of Cash Flows for the year ended
December 31, 2000 and for the three months ended  December 31, 1999.  Our audits
also included the  financial  statement  schedule  listed in Part IV at Item 14.
These   financial   statements   and  financial   statement   schedule  are  the
responsibility of the Company's management.  Our responsibility is to express an
opinion on the financial  statements and financial  statement  schedule based on
our audits. The consolidated  financial statements of the Company for the fiscal
years ended  September  30, 1999 and 1998 were audited by other  auditors  whose
report, dated November 4, 1999 (except with respect to matters discussed in Note
13, as to which the date is December 17, 1999), expressed an unqualified opinion
on those statements.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit to obtain  reasonable  assurance  about  whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In our opinion,  such 2000 and 1999 consolidated  financial  statements  present
fairly,  in all  material  respects,  the  financial  position of the Company at
December 31, 2000 and 1999, and the results of its operations and its cash flows
for the year ended December 31, 2000 and for the three months ended December 31,
1999 in conformity with accounting  principles  generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when
considered  in  relation  to the basic  financial  statements  taken as a whole,
presents fairly in all material respects the information set forth therein.

As  discussed in Notes 1D and 2,  respectively,  to the  consolidated  financial
statements,  effective  January 1, 2000, the Company changed its fiscal year end
to December 31 and its method of accounting  for operating  revenues  associated
with its regulated utility operations.


s/DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 2001 (February 16, 2001 as to Note 15)


<PAGE>



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

          We  have  audited  in  accordance  with  generally  accepted  auditing
standards,  the consolidated  financial  statements of Public Service Company of
North  Carolina,  Incorporated  included in this Form 10-K,  and have issued our
report  thereon  dated  November  4, 1999  (except  with  respect to the matters
discussed in Note 13, as to which the date is December 17, 1999).

         Our audit was made for the  purpose  of  forming  an  opinion  on those
statements  taken  as a  whole.  The  schedules  listed  in the  index  are  the
responsibility of the Registrant's  management and are presented for purposes of
complying with the Securities and Exchange  Commission's  rules and are not part
of the basic  financial  statements.  These schedules have been subjected to the
auditing procedures applied in the audit of the basic financial  statements and,
in our  opinion,  fairly  state in all  material  respects  the  financial  data
required to be set forth therein in relation to the basic  financial  statements
taken as a whole.

s/Arthur Andersen LLP
Charlotte, North Carolina
November 4, 1999



<PAGE>



<TABLE>


PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS

-------------------------------------------------------------------------- ------------------------ --------------------------
                                                                                  Successor                Predecessor
                                                                                December 31,              December 31,
Millions of dollars                                                                 2000                      1999
-------------------------------------------------------------------------- ------------------------ --------------------------
Assets

<S>                     <C>                                                           <C>                     <C>
Gas Utility Plant (Note 1)                                                            $787                    $768
  Less - Accumulated depreciation                                                      263                      245
  Acquisition Adjustment, net of accumulated amortization (Notes 1 & 3)                452                         -
-------------------------------------------------------------------------- ------------------------ --------------------------
Gas Utility Plant, Net                                                                 976                      523
-------------------------------------------------------------------------- ------------------------ --------------------------

Nonutility Property and Investments, net of accumulated depreciation                     34                      31
-------------------------------------------------------------------------- ------------------------ --------------------------

Current Assets:
  Cash and temporary investments (Note 1)                                                 7                        9
  Restricted cash and temporary investments (Note 1)                                      5                        3
  Receivables (net of provisions for uncollectible accounts
    of $2.4 million for 2000 and $2.7 million for 1999)                                 149                      59
  Inventories (at average cost):
      Stored gas                                                                         32                      29
      Materials and supplies                                                              7                        7
  Deferred gas costs, net  (Note 2)                                                       9                      27
  Other                                                                                   1                        1
-------------------------------------------------------------------------- ------------------------ --------------------------
Total Current Assets                                                                   210                      135
-------------------------------------------------------------------------- ------------------------ --------------------------

Deferred Charges and Other Assets:
   Due from affiliate-pension asset   (Note 6)                                           10                        -
   Other                                                                                 18                        9
-------------------------------------------------------------------------- ------------------------ --------------------------
Total Deferred Charges and Other Assets                                                  28                        9
-------------------------------------------------------------------------- ------------------------ --------------------------
    Total                                                                          $1,248                     $698
========================================================================== ------------------------ ==========================
========================================================================== ------------------------ ==========================

Capitalization and Liabilities
Capitalization:
   Common equity (Note 9)                                                             $712                    $232
   Long-term debt, net (Notes 7 & 11)                                                  145                      151
-------------------------------------------------------------------------- ------------------------ --------------------------
Total Capitalization                                                                    857                     383
-------------------------------------------------------------------------- ------------------------ --------------------------

Current Liabilities:
   Short-term borrowings (Notes 8 & 11)                                                125                      138
   Current portion of long-term debt (Note 7)                                             4                        7
   Accounts payable                                                                     84                       50
   Accrued taxes                                                                          3                        5
   Customer prepayments and deposits                                                      8                        7
   Advances from parent                                                                 44                         -
   Dividends declared and interest accrued                                                5                        8
   Other                                                                                  6                        2
-------------------------------------------------------------------------- ------------------------ --------------------------
Total Current Liabilities                                                              279                      217
-------------------------------------------------------------------------- ------------------------ --------------------------

Deferred Credits and Other Liabilities:
   Deferred income taxes, net (Notes 1 & 10)                                            82                       75
   Deferred investment tax credits (Notes 1 & 10)                                         3                        3
   Accrued pension cost (Note 6)                                                          -                        3
   Due to affiliate-postretirement benefits   (Note 6)                                   10                        -
   Other                                                                                 17                       17
-------------------------------------------------------------------------- ------------------------ --------------------------
Total Deferred Credits and Other Liabilities                                            112                       98
-------------------------------------------------------------------------- ------------------------ --------------------------
    Total                                                                          $1,248                     $698
========================================================================== ------------------------ ==========================



See Notes to Consolidated Financial Statements.


<PAGE>





PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

----------------------------------------------------------- --------------- -----------------------------------------------------
                                                              Successor                         Predecessor
----------------------------------------------------------- --------------- ----------------- -----------------------------------
                                                                 Year         Three Months
                                                                Ended            Ended                Fiscal Year Ended
                                                             December 31,     December 31,     September 30,     September 30,
Millions of dollars                                              2000             1999              1999              1998
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

<S>                                                              <C>              <C>               <C>               <C>
Operating Revenues                                               $547             $81               $298              $330
Cost of Gas                                                       375               41               133               174
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Gross Margin                                                      172               40               165               156
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

Operating Expenses:
   Operation and maintenance                                       67              18                  71                60
   Depreciation and amortization                                   42               7                  26                25
   Other taxes                                                       6              2                  15                17
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Total Operating Expenses                                          115              27                112               102
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

Operating Income                                                    57             13                  53                54

Other Income, net                                                    8              1                   6                 5

Interest Charges                                                   20                5                 18                18
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

Income Before Income Taxes and
  Cumulative Effect of Accounting Change                           45                9                 41                41

Income Taxes                                                       24                4                 17                16
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

Income Before Cumulative Effect of Accounting Change               21               5                  24                25

Cumulative Effect of Accounting Change, net of taxes
(Note 2)                                                             7               -                   -                -
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------

Net Income                                                         28                5                 24                25
Retained Earnings at Beginning of Period                           73              73                  70                64
Acquisition of  Company                                           (73)               -                  -                 -
Common Stock Cash Dividends Declared                              (19)              (5)               (21)              (19)
----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
=========================================================== =============== ================= ================= =================
Retained Earnings at End of Period                                 $9             $73                $73               $70
=========================================================== =============== ================= ================= =================

See Notes to Consolidated Financial Statements.




<PAGE>




PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS


--------------------------------------------------------- ----------------- -----------------------------------------------------
                                                             Successor                          Predecessor
--------------------------------------------------------- ----------------- ------------------ ----------------------------------
                                                                Year          Three Months
                                                               Ended              Ended                Fiscal Year Ended
                                                            December 31,      December 31,      September 30,    September 30,
Millions of  dollars                                            2000              1999              1999              1998
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------

Cash Flows From Operating Activities:
<S>                                                             <C>                 <C>              <C>              <C>
   Net income                                                   $28                 $5               $24              $25
   Adjustments to reconcile net income to net cash
provided from (used in) operating activities:
         Cumulative effect of accounting change, net of
taxes                                                             (7)                -                 -                -
         Depreciation and amortization                            47                 8                29               28
         Over (under) collections, fuel adjustment
clause                                                             9                 -                 5               (6)
         Change in operating assets and liabilities:
           (Increase) decrease in receivables, net              (77)               (49)               (9)              11
           (Increase) decrease in inventories                     (3)                 -               (5)              (3)
           (Increase) decrease in deferred gas cost                5                 (8)              (5)                6
           Increase (decrease) in accounts payable and
advances                                                         78                  39                5               (7)
           Increase (decrease) in accrued pension cost             -                 (1)              (3)              (2)
           Increase (decrease) in postretirement payable          1                   -                -                 -
           Increase (decrease) in deferred income
taxes, net                                                         9                  -                8                7
         Other, net                                              (14)                 -                1               (5)
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used In) Operating Activities             76                 (6)             50                54
--------------------------------------------------------- -----------------                    ---------------- -----------------
                                                                            ------------------

Cash Flows From Investing Activities:
   Construction expenditures                                     (39)              (12)             (44)              (65)
   Sales of assets                                                 5                  -                -                -
   Nonutility and other                                          (1)                (1)               (5)              (2)
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used For) Investing Activities           (35)              (13)             (49)              (67)
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------

Cash Flows From Financing Activities:
   Issuance of common stock                                        -                  -                6               10
   Increase (decrease) in short-term borrowings, net             (13)               34               34                33
   Retirement of long-term debt and common stock                  (9)                (8)            (17)              (10)
   Cash dividends                                                (21)                (5)            (20)              (19)
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used For) Financing Activities           (43)               21                 3               14
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------

Net (Decrease) Increase in Cash and Temporary
Investments                                                       (2)                2                 4                 1
Cash and Temporary Investments at Beginning of Period              9                 7                 3                 2
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
--------------------------------------------------------- ----------------- ------------------ ---------------- -----------------

Cash and Temporary Investments at End of Period                   $7                $9                $7               $3
========================================================= ================= ================== ================ =================

Supplemental Cash Flow Information:

Cash paid during the period for:
   Interest (net of capitalized interest of $1.0,
     $0.1, $0.6  and $0.6)                                           $21            $5                $18               $18

   Income taxes                                                   25                  -               7                12


In connection  with the acquisition of Public Service Company of North Carolina,
Inc.  by SCANA  Corporation,  $21  million in common  stock was  cancelled.  The
application  of  push-down  accounting  for  the  acquisition  resulted  in  the
recording of a $466 million acquisition adjustment.


See Notes to Consolidated Financial Statements.


<PAGE>



PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CAPITALIZATION

-------------------------------------------------------------------------- ---------------- ----------------
                                                                              Successor       Predecessor
-------------------------------------------------------------------------- ---------------- ----------------
December 31, (Millions of dollars)                                              2000             1999
-------------------------------------------------------------------------- ---------------- ----------------

Common Equity:
   Common stock, $1 par, 1,000 shares authorized and issued in 2000;
<S>   <C>                           <C>                         <C>                <C>            <C>
      30,000,000 shares authorized, 20,577,967 shares issued in 1999               $-             $21

  Capital in excess of par value                                                  703             138
  Retained earnings                                                                 9              73
-------------------------------------------------------------------------- ---------------- ----------------
Total Common Equity                                                              712              232
-------------------------------------------------------------------------- ---------------- ----------------

Long-term Debt:
  Senior debentures (unsecured) -
     10% due 2003                                                                    -               4
     10% due 2004                                                                  17               22
     8.75%  due 2012                                                               32               32
     6.99% due 2026                                                                 50              50
     7.45% due 2026                                                                 50              50
-------------------------------------------------------------------------- ---------------- ----------------
                                                                                  149             158
  Less - Current maturities                                                        (4)              (7)
-------------------------------------------------------------------------- ---------------- ----------------
Total Long-Term Debt, Net                                                         145              151
-------------------------------------------------------------------------- ---------------- ----------------
========================================================================== ================ ================
Total Capitalization                                                            $857             $383
========================================================================== ================ ================
</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 (PSNC), a public
utility,  was  organized  as a North  Carolina  corporation  in 1938.  Effective
January 1, 2000 the acquisition of PSNC by SCANA  Corporation  (SCANA),  a South
Carolina holding company,  was consummated in a business  combination  accounted
for as a purchase.  As a result,  PSNC became a wholly owned subsidiary of SCANA
incorporated under the laws of South Carolina.  PSNC is engaged predominantly in
the  transportation,  distribution  and  sale  of  natural  gas to  residential,
commercial and industrial customers in North Carolina.

         The accompanying Consolidated Financial Statements include the accounts
of PSNC and its subsidiary companies, PSNC Production Corporation,  SCANA Public
Service Company,  L.L.C. (formerly Sonat Public Service Company,  L.L.C.), Clean
Energy  Enterprises,  Inc.,  PSNC  Blue  Ridge  Corporation,  and PSNC  Cardinal
Pipeline  Company  (collectively,  the "Company").  The accounts of SCANA Public
Service  Company,  L.L.C.  are included only for the period  subsequent to their
acquisition  (See Note 4).  Investments in other affiliates in which the Company
has the ability to exercise  influence over operating and financial policies are
accounted for under the equity  method.  Significant  intercompany  balances and
transactions have been eliminated in consolidation.

         Affiliated Transactions

         At  December  31, 2000 PSNC had  recorded  $4.3  million in  associated
company receivables and $1.7 million in associated company payables with various
SCANA subsidiaries. These amounts are included in PSNC's accounts receivable and
accounts payable, respectively.

B.       Basis of Accounting

         PSNC  accounts  for  its  regulated  utility  operations,   assets  and
liabilities  in  accordance  with  the  provisions  of  Statement  of  Financial
Accounting  Standards (SFAS) 71. This accounting  standard  requires  cost-based
rate-regulated utilities to recognize in their financial statements revenues and
expenses  in  different   time  periods  than  do   enterprises   that  are  not
rate-regulated.  As a  result,  PSNC has  recorded,  as of  December  31,  2000,
approximately   $21.0  million  and  $4.6  million  of  regulatory   assets  and
liabilities,  respectively,  including  amounts recorded for deferred income tax
liabilities of approximately $0.4 million. The regulatory assets are recoverable
through rates.  In the future,  as a result of  deregulation or other changes in
the regulatory  environment,  PSNC 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 PSNC's
results of operations in the period the write-off  would be recorded,  but it is
not expected that cash flows or financial position would be materially affected.

C.       System of Accounts

         The accounting  records of PSNC are  maintained in accordance  with the
Uniform System of Accounts prescribed by the National  Association of Regulatory
Utility  Commissioners  (NARUC) and as adopted by the North  Carolina  Utilities
Commission (NCUC).

D.       Change in Fiscal Year

         PSNC  changed its fiscal year end to  December  31 from  September  30,
effective January 1, 2000.

E.       Utility Plant

         Utility plant is stated  substantially  at original  cost. The costs of
additions,  renewals and betterments to utility plant,  including  direct labor,
material and indirect charges for engineering,  supervision and an allowance for
funds  used  during  construction,  are added to  utility  plant  accounts.  The
original cost of utility  property  retired or otherwise  disposed of is removed
from  utility  plant  accounts  and  generally  charged,  along with the cost of
removal,  less  salvage,  to  accumulated  depreciation.  The costs of  repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.

F.       Allowance for Funds Used During Construction (AFC)

         AFC, a noncash  item,  reflects  the period cost of capital  devoted to
plant under construction.  This accounting practice results in the inclusion of,
as a component of construction  cost, the cost of debt 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
calculated  AFC  composite  rates were 6.8 percent for the year ended 2000,  6.4
percent for the three  months  ended  December  31, 1999 and 5.5 percent and 5.9
percent for the fiscal years ended 1999 and 1998,  respectively.  These rates do
not exceed the maximum allowable rate as calculated under FERC Order No. 561.

G.       Revenue Recognition

         Revenues are recorded  during the  accounting  period in which services
are  provided  to  customers,  and  include  estimated  amounts  for natural gas
delivered,  but not yet  billed.  Prior to January 1, 2000  revenues  related to
regulated gas services were  recorded only as customers  were billed.  (See Note
2.)

         PSNC'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.  Additionally,  PSNC can recover its margin losses on
negotiated  gas sales to certain  large  commercial/industrial  customers in any
manner  authorized  by the  NCUC.  At  December  31,  2000  and  1999  PSNC  had
undercollected from customers pursuant to Rider D approximately $9.3 million and
$16.7 million, respectively, which is in "Deferred Gas Costs, net."

         PSNC's gas rate schedules for  residential,  small commercial and small
industrial customers include a weather normalization adjustment, which minimizes
fluctuations  in  gas  revenues  due  to  abnormal  weather   conditions.   PSNC
establishes  its  commodity  cost of gas for  large  commercial  and  industrial
customers on the basis of market prices for natural gas as approved by the NCUC.

H.       Depreciation and Amortization

         Provisions for  depreciation  and  amortization  are recorded using the
straight-line method and are based on the estimated service lives of the various
classes  of  property.   The  composite  weighted  average   depreciation  rates
approximate  4.1 percent for the year ended  December 31, 2000,  4.1 percent for
the three months ended December 31, 1999 and 3.9 percent and 4.0 percent for the
fiscal years ended September 30, 1999 and 1998.

         The acquisition  adjustment related to the acquisition of PSNC by SCANA
is being amortized over a 35-year period using the straight-line method.

I.       Income Taxes

         In 2000 PSNC 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.

J.       Debt Expense

            PSNC amortizes  issuance  costs for its debentures  over the life of
the related debt. PSNC is amortizing the redemption  premium and the unamortized
issuance costs on its previously  refunded Series K First Mortgage Bonds over 15
years (1987-2002), in accordance with the treatment authorized by the NCUC.


<PAGE>




K.       Environmental

         PSNC  maintains  an  environmental  assessment  program to identify and
assess  current  and former  operation  sites that could  require  environmental
cleanup.  As  site  assessments  are  initiated,   estimates  are  made  of  the
expenditures,  if any, deemed  necessary to investigate and remediate each site.
These  estimates  are  refined  as  additional  information  becomes  available;
therefore,  actual  expenditures  could differ  significantly  from the original
estimates.  Amounts  estimated  and  accrued  to date for site  assessments  and
cleanup relate to regulated operations.  Such amounts are deferred and amortized
with recovery provided through rates.

L.       Cash and Temporary Investments

         PSNC considers temporary cash investments having original maturities of
three months or less to be cash  equivalents.  Temporary  cash  investments  may
include repurchase  agreements,  U.S. Treasury bills, federal agency securities,
certificates of deposit and high-grade commercial paper.

         Since  fiscal  1992,  PSNC  has  received  refunds  from  its  pipeline
transporters  for which the investment and use have been  restricted by an order
of the NCUC.  Pursuant to an order of the NCUC,  these funds are segregated from
PSNC's  general funds and will be used for expansion of PSNC's  facilities  into
unserved  territories.  These refunds,  along with interest earned thereon,  are
periodically transferred to the Office of the State Treasurer of North Carolina.
The  balance  not  transferred  is reported  in  restricted  cash and  temporary
investments.

         At  December  31,  2000 the balance in  restricted  cash and  temporary
investments  includes  approximately  $4.5  million  in  supplier  refunds to be
returned to customers in the form of a bill credit  during the first  quarter of
2001.  This  refund to  customers  was  approved  by the NCUC to help defray the
unusually  high cost of natural gas  experienced  during the most recent heating
season.

M.       Recently Issued Accounting Standard and Bulletin

         In June 1998 the  Financial  Accounting  Standards  Board (FASB) issued
SFAS 133,  "Accounting for Derivative  Instruments  and Hedging  Activities." In
June 2000 the FASB issued SFAS 138, which amends certain  provisions of SFAS 133
to expand the normal  purchase and sale  exemption  for supply  contracts and to
redefine  interest rate risk to reduce sources of  ineffectiveness,  among other
things. PSNC's adoption of SFAS 133, as amended, on January 1, 2001 did not have
a material  impact on PSNC's  results  of  operations,  cash flows or  financial
position.

        In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition
in Financial  Statements"  was issued by the Securities and Exchange  Commission
(SEC),  and  provides  the SEC  staff's  views in  applying  generally  accepted
accounting principles to selected revenue recognition issues. PSNC's adoption of
this  bulletin  in the fourth  quarter  of 2000 had no impact on its  results of
operations, cash flows or financial position.

N.       Reclassifications

         Certain  amounts from prior periods have been  reclassified  to conform
with the presentation adopted for 2000.

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.


<PAGE>




2.       CUMULATIVE EFFECT OF ACCOUNTING CHANGE

         Effective  January 1, 2000 PSNC  changed its method of  accounting  for
operating  revenues  associated with its regulated utility operations from cycle
billing to full accrual.  The cumulative effect of this change was approximately
$6.6 million,  net of taxes.  Accruing  unbilled  revenues more closely  matches
revenues  and  expenses.   Unbilled  revenues  represent  the  estimated  amount
customers will be charged for service  rendered but not yet billed as of the end
of the accounting  period.  At December 31, 1999 the gas costs  associated  with
unbilled  revenues were deferred.  Beginning  January 1, 2000 these costs are no
longer deferred.

         If this method had been  applied  retroactively,  net income would have
been $11.0  million for the three  months ended  December 31, 1999,  compared to
$5.1 million , as previously reported.  Further, if this method had been applied
retroactively  to the fiscal years ended  September 30 1999 and 1998, the impact
on net income would not have been material.

3.       ACQUISITION BY SCANA CORPORATION

               On  February  10,  2000  the  acquisition  of PSNC by  SCANA  was
consummated in a business combination accounted for as a purchase. PSNC became a
wholly owned  subsidiary  of SCANA  effective  January 1, 2000.  Pursuant to the
Agreement and Plan of Merger,  PSNC  shareholders were paid  approximately  $212
million  in cash  and 17.4  million  shares  of SCANA  common  stock  valued  at
approximately $488 million.

               PSNC has  recorded  a utility  plant  acquisition  adjustment  of
approximately $466 million,  which reflects the excess of SCANA's purchase price
over the fair value of PSNC's net assets at January 1, 2000.  The  adjustment is
being  amortized  over 35 years on the  straight-line  basis.  Common  equity at
December 31, 2000 includes the effect of the acquisition adjustment.

               PSNC agreed to pay approximately $5 million to ten key executives
under severance  agreements  related to the acquisition.  Severance  benefits of
approximately  $2.7  million  have  been  paid to  seven  key  executives  whose
positions were eliminated.  In addition,  approximately $3.1 million was paid to
former directors of PSNC in connection with deferred compensation and retirement
plans,  and  approximately  $8.1  million  was paid to  participants  in  PSNC's
nonqualified stock option plans.

4.       ACQUISITION OF SONAT PUBLIC SERVICE COMPANY

       Effective   December   31,  1999  PSNC   Production   Corporation   (PSNC
Production),  a wholly owned  subsidiary  of PSNC,  purchased  the remaining 50%
membership  interest in Sonat  Public  Service  Company,  L.L.C.  (Sonat).  As a
result,  Sonat  became  a  wholly  owned  subsidiary  of PSNC  Production.  PSNC
Production  paid $5.3 million to acquire this interest.  Sonat was  subsequently
renamed SCANA Public Service Company, L.L.C. (SCANA Public Service).

5.       RATE AND OTHER REGULATORY MATTERS

         A. On April 6,  2000 the NCUC  issued  an order  permanently  approving
PSNC's request to establish its commodity  cost of gas for large  commercial and
industrial  customers  on the basis of market  prices for natural  gas. The NCUC
previously  allowed PSNC use of this mechanism on a trial basis.  This procedure
ensures  that the amount paid by PSNC for  natural gas to serve these  customers
approximates the amount collected from them.

         B. A state  expansion fund,  established by the North Carolina  General
Assembly  in  1991  and  funded  by  refunds  from  PSNC's  interstate  pipeline
transporters,  provides  financing for expansion into areas that otherwise would
not be  economically  feasible  to serve.  On  December  30,  1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison,  Jackson and
Swain Counties.  Pursuant to state  statutes,  the NCUC required PSNC to forfeit
its  exclusive  franchises  to serve six  counties  in  western  North  Carolina
effective January 31, 2000 because these counties were not receiving any natural
gas service. Madison, Jackson and Swain Counties were included in the forfeiture
order. On June 29, 2000 the NCUC approved PSNC's requests for  reinstatement  of
its  exclusive   franchises   for  Madison,   Jackson  and  Swain  Counties  and
disbursement of up to $28.4 million from PSNC's expansion fund for this project.
PSNC  estimates  that  the  cost of this  project  will be  approximately  $31.4
million.

         C. On  December  7,  1999  the  NCUC  issued  an  order  approving  the
acquisition of PSNC by SCANA.  As specified in the NCUC order,  PSNC reduced its
rates by  approximately  $1 million in August 2000, will reduce rates another $1
million in August 2001 and has agreed to a five-year  moratorium on general rate
cases.  General rate relief can be obtained  during this period to recover costs
associated  with  materially  adverse  governmental  actions  and force  majeure
events.

         D. On February 22, 1999 the NCUC  approved  PSNC's  application  to use
expansion  funds to extend  natural  gas  service  into  Alexander  County,  and
authorized  disbursements from the fund of approximately $4.3 million based upon
budgeted  construction  cost of  approximately  $6.2 million.  Most of Alexander
County lies within PSNC's certificated  service territory and did not previously
have  natural gas  service.  The  project  was  completed  and  customers  began
receiving natural gas service in March 2000.

         E. On October 30, 1998 the NCUC issued an order in PSNC's  general rate
case filed in April 1998. The order,  effective  November 1, 1998,  granted PSNC
additional  revenue of $12.4 million and allowed a 9.82 percent  overall rate of
return on PSNC's net utility  investment.  It also approved the  continuation of
the  Weather  Normalization  Adjustment  (WNA) and Rider D  mechanisms  and full
margin  transportation  rates.  PSNC's  Rider D rate  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.  On  February  4, 2000 in
response to an appeal by the Carolina Utility Customers  Association,  Inc., the
Supreme Court of North Carolina affirmed the NCUC order.

6.       EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS

         Employee Benefit Plans

                         Since  July 1, 2000 PSNC has  participated  in  SCANA's
noncontributory defined benefit pension plan,
which  covers  substantially  all  permanent  employees.  SCANA's  pension  plan
benefits for PSNC  employees are calculated  using a cash balance  formula under
which employees earn benefits through monthly compensation and interest credits.
SCANA's  policy  has  been  to fund  the  plan to the  extent  permitted  by the
applicable  Federal  income tax  regulations  as  determined  by an  independent
actuary.

             Also,  since July 1, 2000 PSNC has  participated in SCANA's plan to
provide certain  unfunded health care and life insurance  benefits to active and
retired  employees.  Retirees  share in a portion of their medical care cost and
are provided life insurance  benefits at no charge.  The cost of  postretirement
benefits other than pensions are accrued  during the years the employees  render
the service necessary to be eligible for the applicable benefits.

Prior to July 1,  2000 PSNC and its  subsidiaries  sponsored  a  noncontributory
defined benefit pension plan covering substantially all employees.  The benefits
were based on years of service and the employee's  compensation  during the five
consecutive   years  of  employment  that  produced  the  highest  average  pay.
Contributions to the plan were determined on an annual basis, with the amount of
such contributions being within the range of the minimum required funding amount
and the maximum amount deductible for Federal income tax purposes. Prior to July
1, 2000 PSNC also provided  certain health care and life  insurance  benefits to
its  employees.  Retirees were required to contribute  toward the costs of their
medical care coverage. The costs of postretirement  benefits other than pensions
were accrued during the years the employees rendered the service necessary to be
eligible for the applicable benefits.

         During the fiscal  year  ended  September  30,  1999,  PSNC  recognized
pension  gains of $1.8  million  and a net  curtailment  loss on  postretirement
benefit obligations of $0.5 million directly related to severance activity under
restructuring discussed further in Note 13.

         The fair  value of  PSNC's  common  stock  held by its plan at June 30,
2000,  December  31,  1999,  and  September  30,  1999  measurement  dates  were
approximately $0.0 million, $1.4 million and $1.3, million respectively.

         As  discussed  above,  effective  July  1,  2000,  PSNC's  pension  and
postretirement  plans were merged with  SCANA's  plans.  At the time of the plan
mergers,  PSNC had  recognized  a prepaid  pension  cost of  approximately  $9.0
million and a  postretirement  welfare plan  obligation  of  approximately  $9.1
million.  For the period July 1 through  December 31, 2000,  PSNC's net periodic
benefit  income was  approximately  $0.6 million income for the pension plan and
PSNC's net  periodic  benefit cost was  approximately  $0.7 million cost for the
postretirement plan.

         Disclosures  required for these PSNC's plans under SFAS 132 "Employer's
Disclosures  about Pensions and Other  Postretirement  Benefits" for the periods
prior to the plan mergers are set forth in the following tables:

Components of Net Periodic Benefit Cost

<TABLE>
                                                   Retirement Benefits

                                          Six Months          Three Months

                                            Ended                Ended               Year Ended              Year Ended
                                          June 30,            December 31,          September 30,          September 30,


Millions of dollars                         2000                  1999                  1999                    1998
------------------------------------ -------------------- --------------------- ---------------------- -----------------------
<S>                                         <C>                    <C>                  <C>                     <C>
Service cost                                $0.8                   $0.5                 $2.3                    $2.1
Interest cost                                 1.6                    0.8                  3.0                     3.0
Expected return on plan assets              (2.2)                  (0.8)                 (3.1)                   (2.7)
Prior service cost amortization                 -                    0.1                  0.6                     0.6
Transition amount amortization                  -                   (0.1)                (0.3)                   (0.3)
==================================== ==================== ===================== ====================== =======================
Net periodic benefit cost                   $0.2                   $0.5                 $2.5                    $2.7
==================================== ==================== ===================== ====================== =======================


                                              Other Postretirement Benefits

                                         Six Months           Three Months

                                            Ended                Ended               Year Ended              Year Ended
                                          June 30,            December 31,          September 30,          September 30,


Millions of dollars                         2000                  1999                  1999                    1998
------------------------------------ -------------------- --------------------- ---------------------- -----------------------
<S>                                          <C>                  <C>                    <C>                    <C>
Service cost                                 $0.1                 $0.1                   $0.3                   $0.3
Interest cost                                 0.4                   0.2                   0.6                     0.6
Prior service cost amortization                  -                    -                   0.1                       -
Transition amount amortization                   -                    -                   0.2                     0.2
==================================== ==================== ===================== ====================== =======================

Net periodic benefit cost                    $0.5                 $0.3                   $1.2                   $1.1
==================================== ==================== ===================== ====================== =======================

Weighted-Average Assumptions

                                                    Retirement Benefits

                                         Six Months           Three Months

                                            Ended                Ended               Year Ended             Year Ended
                                          June 30,            December 31,          September 30,         September 30,

                                            2000                  1999                  1999                   1998
------------------------------------ -------------------- --------------------- ---------------------- ---------------------

Discount rate                               8.00%                8.00%                  7.50%                 6.75%
Expected return on plan assets              9.50%                9.50%                  8.00%                 8.00%
Rate of compensation increase            Age-related          Age-related            Age-related           Age-related



<PAGE>




                                               Other Postretirement Benefits

                                         Six Months          Three Months

                                            Ended                Ended               Year Ended              Year Ended
                                          June 30,           December 31,          September 30,           September 30,

                                            2000                 1999                   1999                    1998
------------------------------------ -------------------- -------------------- ----------------------- -----------------------
<S>                                         <C>                  <C>                   <C>                     <C>
Discount rate                               8.00%                8.00%                 7.50%                   6.75%
Expected return on plan assets               n/a                  n/a                   n/a                     n/a
Rate of compensation increase            Age-related          Age-related           Age-related             Age-related


Changes in Benefit Obligations

                                                    Retirement Benefits

                                                        Six Months           Three Months

                                                           Ended                Ended                Year Ended
                                                         June 30,            December 31,           September 30,


Millions of dollars                                        2000                  1999                   1999
--------------------------------------------------- -------------------- --------------------- ------------------------
<S>                                                        <C>                  <C>                     <C>
Benefit obligation, beginning of period                    $38.7                $44.1                   $46.6
Service cost                                                 0.8                   0.5                    2.3
Interest cost                                                1.6                   0.8                    3.0
Settlement payments                                             -                    -                   (7.2)
Benefits paid                                                (2.5)                (2.2)                  (0.5)
Curtailment gain                                                 -                   -                   (1.2)
Actuarial (gain) loss                                         1.3                 (4.5)                   1.1
--------------------------------------------------- -------------------- --------------------- ------------------------
Benefit obligation at end of period                        $39.9                $38.7                   $44.1
=================================================== ==================== ===================== ========================


                                               Other Postretirement Benefits

                                                         Six Months          Three Months

                                                           Ended                 Ended               Year Ended
                                                          June 30,           December 31,           September 30,


Millions of dollars                                         2000                 1999                   1999
--------------------------------------------------- --------------------- -------------------- ------------------------
<S>                                                          <C>                 <C>                    <C>
Benefit obligation, beginning of period                      $8.9                $9.3                   $9.0
Service cost                                                  0.1                    -                    0.3
Interest cost                                                 0.4                  0.2                    0.6
Benefits paid                                                (0.3)               (0.1)                   (0.6)
Curtailment gain                                                 -                   -                   (0.3)
Actuarial (gain) loss                                          2.1                (0.5)                   0.3
--------------------------------------------------- --------------------- -------------------- ------------------------
Benefit obligation at end of period                         $11.2                $8.9                   $9.3
=================================================== ===================== ==================== ========================




<PAGE>



Change in Plan Assets

                                                    Retirement Benefits

                                                         Six Months          Three Months

                                                           Ended                 Ended               Year Ended
                                                          June 30,           December 31,           September 30,


Millions of dollars                                         2000                 1999                   1999
--------------------------------------------------- --------------------- -------------------- ------------------------
<S>                                                        <C>                  <C>                     <C>
Fair value of plan assets, beginning of period             $47.9                $45.0                   $43.7
Actual return on plan assets                                  0.8                  3.1                    5.3
Company contribution                                            -                  2.0                    3.7
Benefits paid                                               (2.5)                 (2.2)                  (7.7)
--------------------------------------------------- -------------------- --------------------- ------------------------
Fair value of plan assets at end of period                 $46.2                $47.9                   $45.0
=================================================== ==================== ===================== ========================

Funded Status of Plans

                                                    Retirement Benefits

                                                        Six Months           Three Months

                                                           Ended                Ended                Year Ended
                                                         June 30,            December 31,           September 30,


Millions of dollars                                        2000                  1999                   1999
--------------------------------------------------- -------------------- --------------------- ------------------------
<S>                                                        <C>                   <C>                    <C>
Funded status, beginning of period                         $6.3                  $9.2                   $0.9
Unrecognized actuarial (gain) loss                           2.7                (14.4)                  (7.6)
Unrecognized prior service cost                                -                  2.5                     2.7

Unrecognized net transition obligation                         -                 (0.8)                  (1.0)
--------------------------------------------------- -------------------- --------------------- ------------------------
Net asset (liability) recognized in

  Consolidated Balance Sheet                               $9.0                 $(3.5)                 $(5.0)
=================================================== ==================== ===================== ========================

                                               Other Postretirement Benefits

                                                       Six Months          Three Months

                                                         Ended                Ended                 Year Ended
                                                        June 30,           December 31,           September 30,


Millions of dollars                                       2000                 1999                    1999
------------------------------------------------- --------------------- ------------------- ---------------------------
<S>                                                     <C>                    <C>                    <C>
Funded status, beginning of period                      $(11.2)                $(8.9)                 $(9.3)
Unrecognized actuarial (gain) loss                          2.1                 (0.5)                    0.3

Unrecognized prior service cost                               -                  0.4                     0.4

Unrecognized transition obligation                            -                  2.7                     2.8
------------------------------------------------- -------------------- --------------------- --------------------------
Net asset (liability) recognized in

  Consolidated Balance Sheet                             $(9.1)                $(6.3)                 $(5.8)
================================================= ==================== ===================== ==========================

Health Care Trends

The determination of net periodic other postretirement  benefit cost is based on
the following assumptions:


                                                       Six Months          Three Months

                                                         Ended                Ended                 Year Ended
                                                        June 30,           December 31,           September 30,


                                                          2000                 1999                    1999
------------------------------------------------- --------------------- ------------------- ---------------------------
<S>                                                      <C>                  <C>                      <C>
Health care cost trend rate                              8.00%                8.00%                    7.75%
Ultimate health care cost trend rate                     5.50%                5.50%                    4.25%

Year achieved                                            2005                  2005                    2008
</TABLE>

         Stock Compensation Plans

                Prior to SCANA's  acquisition of PSNC effective January 1, 2000,
         PSNC sponsored the stock-based compensation plans described below. PSNC
         applied the intrinsic value method prescribed by Accounting  Principles
         Board Opinion No. 25,  "Accounting  for Stock Issued to Employees"  and
         related  interpretations in accounting for grants made under the plans.
         Because all options  granted after September 30, 1997 were granted with
         exercise  prices equal to the fair market value of the Company's  stock
         on the respective  grant dates, no compensation  expense was recognized
         in connection  with such grants.  If PSNC had  determined  compensation
         expense  for the  issuance  of options  based on the fair value  method
         described in SFAS 123,  "Accounting for Stock-Based  Compensation," net
         income would have been reduced to the pro forma amounts shown below:

                                                Year Ended September 30,
           Millions of dollars                    1999          1998
           --------------------- --------------------------------------------

           Net income            As reported     $24.5          $24.8
                                 Pro forma       $23.7          $23.6


         Nonqualified Stock Option Plans

                PSNC sponsored a 1992 Nonqualified Stock Option Plan (1992 Plan)
         and a 1997  Nonqualified  Stock Option Plan (1997 Plan).  In accordance
         with the 1992 Plan,  options to purchase  PSNC common  stock could have
         been granted to officers and key employees of PSNC at 90 percent of the
         fair  market  value of the stock  determined  on the date of the grant.
         Under the 1997 Plan, options to purchase PSNC's common stock could have
         been granted to officers  and key  employees of PSNC at the fair market
         value of the stock  determined  on the date of the grant.  Options from
         the 1992 Plan and the 1997 Plan were  exercisable  beginning  two years
         from the date of the grant and expired  five years from the date of the
         grant.

                In addition, upon a change in control event, which occurred with
         shareholder  approval of PSNC's  acquisition by SCANA,  all outstanding
         options became exercisable on July 1, 1999.

                Options granted, exercised and canceled under both plans for the
periods indicated were as follows:

                                    Options              Weighted-Average
                                  Outstanding             Exercise Price
 --------------------------------------------------- --------------------------

 September 30, 1997                 463,938                   $14.54
 Granted                            624,000                   $20.64
 Exercised                         (111,375)                  $14.60
 Canceled                           (20,879)                  $16.88
 --------------------------------------------------- --------------------------
 September 30, 1998                 955,684                   $18.46
 Granted                                    -                         -
 Exercised                         (149,212)                  $14.66
 Canceled                          (101,680)                  $20.54
 --------------------------------------------------- --------------------------
 September 30, 1999                 704,792                   $18.97
 Granted                                    -                        -
 Exercised                          (60,647)                  $12.86
 Canceled                                   -                        -
 --------------------------------------------------- --------------------------
 --------------------------------------------------- --------------------------
 December 31,1999                   644,145                   $19.08
 Granted                                    -                        -
 Exercised                         (644,145)                  $19.08
 Canceled                                   -                        -
 --------------------------------------------------- --------------------------
 =================================================== ==========================
 December 31, 2000                          -                        -
 =================================================== ==========================



<PAGE>




                For purposes of pro forma disclosure,  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 1998 was estimated  using the  Black-Scholes  options  pricing model
         with the following weighted average assumptions:

            Risk free interest rates(s)                       5.5% and 5.8%
            Volatility factor                                     15.30%
            Dividend yield                                        4.53%
            Expected life                                       4.5 years

                The weighted  average fair value of  nonqualified  stock options
         granted  during fiscal 1998 was $2.54.  At September 30, 1998,  231,403
         options were  exercisable  at a weighted  average  price of $13.49.  At
         September  30 and  December  31,  1999,  all  outstanding  options were
         exercisable  at the weighted  average  prices  indicated  above.  As of
         December  31,  1999,  the  644,145  outstanding  options had a weighted
         average  remaining  contractual  life of 2.6 years and exercise  prices
         ranging from $12.86 to $21.25.

         Employee Stock Purchase Plan

                Under the 1992 Employee Stock  Purchase  Plan, as amended,  PSNC
         was authorized to issue common stock to its full-time employees, nearly
         all of whom were eligible to participate,  at a purchase price equal to
         90 percent of such common stock's fair value.  This plan was terminated
         effective  June 30,  1999.  In  fiscal  1999 and 1998,  PSNC  issued to
         employees 62,355 and 82,203 shares, respectively.

                For purposes of pro forma disclosure,  the weighted average fair
         value at grant date for employee  stock  options  granted was estimated
         using  the  Black-Scholes  option  pricing  model  with  the  following
         weighted average assumptions:

                                      1999                  1998
 ------------------------------------------- ---------------------

 Risk free interest rate             4.58%                 5.43%
 Volatility factor                  14.96%                15.30%
 Dividend yield                      3.85%                 4.53%
 Expected life                      1 year                1 year

                The weighted  average fair value of each employee stock purchase
         plan  grant   during   fiscal  1999  and  1998  was  $6.52  and  $6.10,
         respectively.

7.       LONG-TERM DEBT

                  The annual amounts of long-term debt  maturities for the years
         2001 through 2005 are summarized as follows:

   ----------------- ----------------- ------------------ -----------------
         Year             Amount             Year              Amount
   ----------------- ----------------- ------------------ -----------------
                            (Millions of Dollars)

         2001               $4.3             2004               $7.5
         2002                4.3             2005                 3.2
         2003                7.5
   ----------------- ----------------- ------------------ -----------------


                Under  the  terms  of the debt  agreements,  there  are  various
         provisions  relating to the maintenance of certain financial ratios and
         conditions,  the most  significant of which could  restrict  payment of
         dividends.  At December 31, 2000, PSNC is in compliance in all material
         respects with the requirements of its debt agreements.



<PAGE>



8.       SHORT-TERM BORROWINGS

         PSNC  pays fees to banks as  compensation  for its  committed  lines of
credit.  Commercial  paper  borrowings are for 270 days or less. At December 31,
2000 committed lines of credit under revolving  credit  agreements  which expire
July 27,  2001 were $125  million.  Unused  lines of credit  were $125  million.
Short-term  borrowings  through  commercial paper at December 31, 2000 were $125
million at a weighted average interest rate of 6.69 percent.

         At  December  31,  1999 PSNC had  committed  lines of credit  with five
commercial  banks and a five-year  revolving line of credit with one bank.  PSNC
also  had  uncommitted  annual  lines  of  credit.  PSNC  paid  fees to banks as
compensation  for its committed  lines of credit.  At December 31, 1999 PSNC had
authorized lines of credit  (committed and  uncommitted) of $195 million,  which
included  unused lines of credit of $57.5 million and  short-term  borrowings of
$137.5 million at a weighted average interest rate of 5.74 percent.

9.       COMMON EQUITY

       The changes in "Common  Equity"  during the year ended December 31, 2000,
the three months ended  December 31, 1999 and fiscal years ended  September  30,
1999 and 1998 are summarized as follows:

                                             Common Shares   Millions of Dollars
--------------------------------------------------------------------------------
Balance at September 30, 1997                 19,770,843          $207.4
    Changes in Retained Earnings:
       Net income                                                   24.8
       Cash Dividends Declared                                     (19.2)
     Issuance of Stock                           503,489             9.8
--------------------------------------------------------------------------------
Balance at September 30, 1998                 20,274,332           222.8
   Changes in Retained Earnings
       Net Income                                                   24.5
       Cash Dividends Declared                                     (20.8)
   Issuance of  Stock                            303,635             6.7
--------------------------------------------------------------------------------
Balance at September 30, 1999                 20,577,967           233.2
   Changes in Retained Earnings:
       Net Income                                                    5.1
       Cash Dividends Declared                                      (6.0)
----------------------------------------------- --------------
Balance at December 31, 1999                  20,577,967           232.3
   Cancellation of Shares Due
     to Acquisition                          (20,576,967)          470.9
   Other Changes in Retained Earnings:
       Net Income                                                   27.8
       Cash Dividends Declared                                     (19.0)
-------------------------------------------------------------------------------
Balance at December 31, 2000                      1,000            $712.0
============================================================== ======= =========



<PAGE>



10.      INCOME TAXES

       Total income tax expense  attributable to income before cumulative effect
of accounting change for the periods indicated is as follows:
<TABLE>

                                                       Successor                        Predecessor
--------------------------------------------------- ---------------- ---------------------------------------------------
                                                         Year          Three Months
                                                         Ended            Ended               Fiscal Year Ended
                                                     December 31,      December 31,     September 30,    September 30,
Millions of dollars                                      2000              1999              1999             1998
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------

Current taxes:
<S>                                                      <C>               <C>               <C>              <C>
      Federal                                            $18.6             $2.9              $9.0             $7.9
      State                                                 3.9             0.6                2.1             1.8
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
            Total current taxes                           22.5              3.5              11.1              9.7
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Deferred taxes, net:
      Federal                                               1.5             0.6                5.4             5.6
      State                                                 0.3             0.1                1.2             1.3
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
            Total deferred taxes                            1.8             0.7                6.6             6.9
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Investment tax credits:
      Amortization of amounts deferred - Federal           (0.4)               -              (0.4)            (0.4)
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
            Total investment tax credits                   (0.4)               -              (0.4)            (0.4)
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
            Total income tax expense                     $23.9             $4.2             $17.3            $16.2
=================================================== ================ ================= ================= ===============

       The  difference   between  actual  income  tax  expense  and  the  amount
calculated  from the  application of the statutory  Federal income tax rate (35%
for  2000,  1999  and  1998) to  pre-tax  income  before  cumulative  effect  of
accounting change is reconciled as follows:

                                                       Successor                        Predecessor
--------------------------------------------------- ---------------- ---------------------------------------------------
                                                         Year          Three Months
                                                         Ended            Ended               Fiscal Year Ended
                                                     December 31,      December 31,     September 30,    September 30,
Millions of dollars                                      2000              1999              1999             1998
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------

Income before cumulative effect
<S>                                                      <C>                <C>             <C>              <C>
   of accounting change                                  $21.2              $5.1            $24.1            $24.8
Total income tax expense:
   Charged to operating expense                           20.6               3.8              15.3             15.1
   Charged to other income                                  3.3              0.4               2.0              1.1
=================================================== ================ ================= ================= ===============
      Total pre-tax income                                 45.1              9.3              41.4             41.0
=================================================== ================ ================= ================= ===============
=================================================== ================ ----------------- ================= ===============

Income taxes on above at statutory
   Federal income tax rate                                15.8               3.3              14.5             14.4
Increases (decreases) attributed to:
   State income taxes (less Federal income tax
effect)                                                     2.8             0.5                2.1               2.0
    Non-deductible book amortization
      of acquisition adjustments                            4.7                -                  -                -
   Amortization of Federal investment tax credits         (0.4)                -              (0.4)             (0.4)
   Other differences, net                                   1.0             0.4                1.1               0.2
--------------------------------------------------- ---------------- ----------------- ----------------- ---------------
=================================================== ================ ================= ================= ===============
        Total income tax expense                         $23.9             $4.2             $17.3             $16.2
=================================================== ================ ================= ================= ===============
</TABLE>



<PAGE>




   The tax effects of significant  temporary  differences  comprising PSNC's net
deferred tax  liability of $80.7  million at December 31, 2000 and $73.8 million
at December 31, 1999 (see Note 1I), are as follows:

                                                   Successor   Predecessor
--------------------------------------------------------------------------
Millions of dollars                                  2000          1999
--------------------------------------------------------------------------

Deferred tax assets:
   Unamortized investment tax credits                $1.0          $1.1
   Other postretirement benefits                        -           2.1
   Pension costs                                        -           2.0
   Deferred compensation                                -           1.0
   Other                                              2.9           4.2
---------------------------------------------------------------- ---------
        Total deferred tax assets                     3.9          10.4
---------------------------------------------------------------- ---------

Deferred tax liabilities:
   Property, plant and equipment                     82.2          80.6
   Other                                              2.4           3.6
---------------------------------------------------------------- ---------
        Total deferred tax liabilities               84.6          84.2
----------------------------------------------------------------  --------
Net deferred tax liability                          $80.7         $73.8
================================================================ =========


11.           FINANCIAL INSTRUMENTS

       The  carrying  amounts  and  estimated  fair  values of PSNC's  financial
instruments at December 31, 2000 and 1999 are as follows:
<TABLE>

      Millions of dollars                                     2000                          1999
      ------------------------------------------- ----------------------------- ------------------------------
                                                                   Estimated                      Estimated
                                                    Carrying         Fair          Carrying         Fair
                                                     Amount          Value          Amount          Value
      ------------------------------------------- -------------- -------------- --------------- --------------
      Assets:
<S>                                                      <C>            <C>            <C>             <C>
        Cash and temporary cash investments              $7             $7             $9              $9
      Liabilities:
        Short-term borrowings                          125            125             138            138
        Long-term debt                                 149            154             157            156
</TABLE>

       The  information  presented  herein  is  based on  pertinent  information
available  as of December 31, 2000 and 1999.  Although  PSNC is not aware of any
factors that would significantly  affect the estimated fair value amounts,  such
financial instruments have not been comprehensively  revalued since December 31,
2000,  and the current  estimated fair value may differ  significantly  from the
estimated fair value that date.

       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 amounts.

o     Fair values of  long-term  debt are based on quoted  market  prices of the
      instruments.  Settlement of long-term  debt may not be possible or may not
      be considered prudent.

o     Short-term borrowings are valued at their carrying amounts.

12.      COMMITMENTS AND CONTINGENCIES

       PSNC owns, or has owned, all or portions of seven sites in North Carolina
on which  manufactured  gas  plants  (MGP)  were  formerly  operated.  Intrusive
investigation (including drilling,  sampling and analysis) has begun at only one
site, and the remaining sites have been evaluated using  historical  records and
observations of current site  conditions.  These  evaluations have revealed that
MGP  residuals  are  present or  suspected  at  several of the sites.  The North
Carolina Department of Environment and Natural Resources has recommended that no
further action be taken with respect to one site. An environmental due diligence
review of PSNC  conducted in February 1999  estimated that the cost to remediate
the remaining sites would range between $11.3 million and $21.9 million.  During
the second quarter of 2000, the review was finalized and the estimated liability
was  recorded.  PSNC is  unable  to  determine  the rate at which  costs  may be
incurred over this time period. The estimated cost range has not been discounted
to present value.  PSNC's associated actual costs for these sites will depend on
a number of factors,  such as actual  site  conditions,  third-party  claims and
recoveries  from other  potentially  responsible  parties (PRP). An order of the
NCUC dated May 11, 1993 authorized  deferral accounting for all costs associated
with the  investigation  and  remediation of MGP sites. As of December 31, 2000,
PSNC has recorded a liability and associated  regulatory asset of $10.2 million,
which reflects the minimum amount of the range, net of shared cost recovery from
other PRPs.  Amounts  incurred to date are not material.  Management  intends to
request  recovery in future rate case filings of MGP cleanup costs  incurred and
not  recovered  from other PRPs and  believes  that all costs  incurred  will be
recoverable in gas rates.

13.      RESTRUCTURING

         During  fiscal 1999,  PSNC recorded net  restructuring  charges of $4.3
million.  These  charges  consisted of  severance  benefits of $3.7  million,  a
one-time payment to 152 employees of $1 million in connection with an automobile
fleet   restructuring,   a  net  curtailment  loss  on  postretirement   benefit
obligations  of $.5  million  offset by pension  gains of $1.8  million  and $.8
million of other restructuring charges.

14.      SEGMENT OF BUSINESS INFORMATION

        PSNC's  reportable  segments  are  listed in the  following  table.  Gas
Distribution  uses  operating  income to  measure  profitability,  while  Energy
Marketing,  which is comprised solely of SCANA Public Service  (formerly Sonat),
uses net  income to measure  profitability.  Affiliate  revenue is derived  from
transactions between reportable  segments.  Prior to December 31, 1999 Sonat was
an equity  investment  and not a segment of business  (see Note 4). PSNC did not
have deferred tax assets for any period reported.  For 2000,  adjustments to net
income and income tax expense  include the  cumulative  effect of the accounting
change described in Note 2.

Disclosure of Reportable Segments
<TABLE>

Millions of dollars
------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
      Year Ended                   Gas              Energy           All           Adjustments/        Consolidated
  December 31, 2000            Distribution        Marketing        Other          Eliminations           Total
------------------------------ ------------------- ---------------- -------------- ------------------- --------------------

<S>                                <C>               <C>              <C>              <C>                 <C>
External Revenue                   $432              $141             $ -              $(26)               $547

Intersegment Revenue                   -                 1             30             (31)                  -
Deprec. & Amort.                      42                -               -                  -                  42

Operating Income                      54              n/a             n/a               3                   57
Interest Expense                      20                -               -                  -                  20

Net Income                          n/a                 2             5                   21                28
Segment Assets                    1,231                35              72                (90)              1,248
Expenditures for
Assets                               39                  -              1                  -                   40

------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
  Three months Ended               Gas              Energy           All           Adjustments/        Consolidated
  December 31, 1999            Distribution        Marketing        Other          Eliminations           Total
------------------------------ ------------------- ---------------- -------------- ------------------- --------------------


<S>                                <C>                                                                      <C>
External Revenue                   $81                n/a             -                   -                 $81

Intersegment Revenue                 -                n/a            $27              $(27)                     -

Deprec. & Amort.                     7               n/a              -                   -                     7
Operating Income                    13               n/a               n/a                -                    13

Interest Expense                     5               n/a              -                   -                     5

Net Income                          n/a               n/a             -            5                        5

Segment Assets                     678                20              58               (58)            698
Expenditures for
Assets                               12               n/a             1                   -            13



<PAGE>




------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
  Fiscal Year Ended                Gas              Energy           All           Adjustments/        Consolidated
  September 31, 1999           Distribution        Marketing        Other          Eliminations           Total
------------------------------ ------------------- ---------------- -------------- ------------------- --------------------


<S>                                <C>                                <C>               <C>                 <C>
External Revenue                   $298              n/a              $6                $(6)                $298

Intersegment Revenue                   -             n/a              39                (39)                     -

Deprec. & Amort.                     26              n/a              1                (1)                     26
Operating Income                     53              n/a               n/a                -                    53

Interest Expense                     18              n/a              -                   -                    18

Net Income                          n/a              n/a              2                  22                    24

Segment Assets                      637              n/a              46                (34)                  649
Expenditures for
Assets                               44              n/a              5                    -                   49

------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
  Fiscal Year Ended                Gas              Energy           All           Adjustments/        Consolidated
  September 31, 1998           Distribution        Marketing        Other          Eliminations           Total
------------------------------ ------------------- ---------------- -------------- ------------------- --------------------


<S>                                <C>                                                                      <C>
External Revenue                   $330              n/a              -                    -                $330
Intersegment Revenue                   -             n/a               $87             $(87)                     -

Deprec. & Amort.                     25              n/a              1                  (1)                   25
Operating Income                     54              n/a               n/a                -                    54

Interest Expense                     18              n/a              -                   -                    18

Net Income                          n/a              n/a              1                  24                    25

Segment Assets                      606              n/a              34               (21)                   619
Expenditures for
Assets                               65              n/a              2                   -                     67

</TABLE>


15.      SUBSEQUENT EVENTS

         PSNC  Production  Corporation and SCANA Public Service Company LLC were
sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA Corporation for $4.4
million, which approximates net book value, effective January 1, 2001.

         On February  16, 2001 PSNC issued  $150  million of  medium-term  notes
having an annual  interest  rate of 6.625  percent and  maturing on February 15,
2011. The proceeds from these borrowings were used to reduce short-term debt and
for general corporate purposes.


<PAGE>




16.      QUARTERLY FINANCIAL DATA  (UNAUDITED)

             (Millions of dollars, except per share amounts)
<TABLE>

-------------------------------------------------------- ------------------------------------------------------------
Year Ended December 31, 2000                               First       Second       Third       Fourth
                                                          Quarter      Quarter     Quarter     Quarter      Annual
-------------------------------------------------------- ----------- ------------ ----------- ----------- -----------

<S>                                                         <C>          <C>         <C>         <C>         <C>
Total operating revenues                                    $171         $80         $76         $220        $547

Operating income (loss)                                    37(1)           (2)         (7)          29         57
Cumulative effect of accounting change, net of taxes            7           -           -            -           7
Net income (loss)                                              26          (5)         (8)         15          28
</TABLE>


Three Months Ended December 31, 1999

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

Total operating revenues                                    $81
Operating income (loss)                                      13
Net income (loss)                                             5

<TABLE>

---------------------------------------------------------------------------------------------------
                                         First       Second       Third       Fourth
Fiscal Year Ended September 30, 1999    Quarter      Quarter     Quarter     Quarter      Annual
-------------------------------------------------- ------------ ----------- ----------- -----------

<S>                                        <C>        <C>           <C>        <C>         <C>
Total operating revenues                   $73        $135          $54        $37         $299
Operating income (loss)                     10          40            7         (3)          54
Net income (loss)                            4          22            2         (3)          25
</TABLE>

(1)Excludes  $14 million of income  taxes  formerly  reported  in first  quarter
operating income.













<PAGE>
















                          PART II, ITEM 9 AND PART III


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

<PAGE>



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE:

            SCANA:  None

                            SCE&G:  None

       PSNC filed on April 3, 2000 a Current  Report on Form 8-K dated March 27,
2000 changing its certifying accountants.

                                    PART III

 ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

SCANA:

       The information  required by Item 10, Directors and Executive Officers of
the  Registrant,  with  respect to executive  officers  is,  pursuant to General
Instruction  G(3) to Form 10-K,  set forth in Part I of this Form 10-K under the
heading  Executive  Officers of SCANA  Corporation on page 23 herein.  The other
information  required by Item 10 is  incorporated  herein by  reference,  to the
captions "Proposal 1 - Nominees For Class II Directors", "Continuing Directors",
and  "Other   Information  -  Section  16(a)  Beneficial   Ownership   Reporting
Compliance" in SCANA's definitive proxy statement for the 2001 annual meeting of
shareholders   which  was  filed  with  the  SEC  pursuant  to  Regulation  14A,
promulgated under the Securities Exchange Act of 1934.

SCE&G: DIRECTORS

       The  directors  listed  below  were  elected  April 27,  2000  (except as
otherwise  indicated)  to hold office  until the next annual  meeting of SCE&G's
stockholders on May 3, 2001.

  Name and Year First
    Became Director      Age    Principal Occupation; Directorships


     Bill L. Amick       57     For more than five years, Chairman of the Board
           (1990)               and Chief Executive Officer of Amick Farms,
                                Inc., Amick Processing, Inc. and Amick Broilers,
                                Inc., Batesburg, SC  (vertically integrated
                                broiler operation).

                                Director,  SCANA  Corporation,   Columbia,  SC.;
                                Public Service Company of North Carolina,  Inc.,
                                (PSNC), Gastonia, NC; Blue Cross and Blue Shield
                                of South Carolina, Columbia, SC.

    James A. Bennett            Since May 2000, President and Chief Executive
         (1997)           40    Officer of South Carolina Community Bank,
                                Columbia, SC.

                                From February 10, 2000 to  May 2000, Economic
                                Development Director, First Citizens Bank,
                                Columbia, SC

                                From December 1998 to February 2000, Senior Vice
                                  President   and   Director   of   Professional
                                  Banking, First Citizens Bank.

                                From December 1994 to December 1998, Senior Vice
                                  President and Director of Community Banking,
                                  First Citizens Bank.

                                Director, SCANA Corporation, Columbia, SC; PSNC,
                                Gastonia, NC.
  William B. Bookhart,
       Jr. (1979)         59    For more than five years, a partner in Bookhart
                                Farms, Elloree, SC (general farming).

                                Director, SCANA Corporation, Columbia, SC; PSNC,
                                Gastonia, NC.


<PAGE>




  Name and Year First
    Became Director       Age    Principal Occupation; Directorships

  William C. Burkhardt     63    Since May 2000, retired President and Chief ,
         (2000)                  Executive Officer of Austin Quality Foods, Inc.
                                 Cary, NC (production and distribution of baked
                                 snacks)

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                 PSNC, Gastonia, NC; Capital Bank, Raleigh, NC.

    Hugh M. Chapman        68    Since June 30, 1997, retired from NationsBank
         (1988)                  South, Atlanta, GA (a division of NationsBank
                                 Corporation, bank holding company).

                                 For more than five years prior to June 30, 1997
                                 Chairman of NationsBank South.

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                   PSNC, Gastonia, NC; West Point-Stevens,  West
                                   Point, GA; PrintPack,  Inc., Atlanta, GA; The
                                   Williams Companies, Inc., Tulsa, OK.

   Elaine T. Freeman 65 For more than five years,  Executive  Director of (1992)
          ETV Endowment of South Carolina, Inc.
                                 (non-profit organization), Spartanburg, SC

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                   PSNC,  Gastonia,  NC;  National Bank of South
                                   Carolina (a member bank of Synovus  Financial
                                   Corporation), Columbia, SC.

Lawrence  M.  Gressette,Jr. 69   Since February 28, 1997, Chairman Emeritus of
         (1987)                  SCANA Corporation, Columbia, SC.

                                 For more than five years prior to February  28,
                                 1997, Chairman of the Board and Chief

                                  Executive Officer of  SCANA Corporation.

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                 PSNC, Gastonia, NC.

   D. Maybank Hagood      39     For more than five years, President and Chief
         (1999)                  Executive Officer of William M. Bird and
                                 Company,   Inc.,   Charleston,   SC  (wholesale
                                distributor of floor covering materials).

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                 PSNC, Gastonia, NC.

     W. Hayne Hipp        61     For more than five years, Chairman, President
         (1983)                  and Chief Executive Officer, The Liberty .
                                 Corporation, Greenville, SC (broadcasting
                                 holding company)

                                 Director, SCANA Corporation, Columbia, SC;
                                 PSNC,  Gastonia, NC; The Liberty Corporation,
                                 Greenville, SC; Wachovia Corporation,
                                 Winston-Salem, NC.

    Lynne M. Miller       49     Since February 1998, Chief Executive Officer of
         (1997)                  Environmental Strategies Corporation, Reston,
                                 VA  (environmental  consulting and  engineering
                                 firm).

                                 For more than five years prior to February
                                 1998, President of Environmental Strategies
                                 Corporation.

                                 Director,  SCANA  Corporation,   Columbia,  SC;
                                 PSNC,  Gastonia,  NC; Adams  National  Bank, (a
                                 Subsidiary of Abigail Adams  National  Bancorp,
                                 Inc.), Washington, DC.


<PAGE>








   Name and Year First
     Became Director       Age    Principal Occupation; Directorships

     Maceo K. Sloan        51     For more than five years, Chairman, President
         (1997)                   and Chief Executive Officer of Sloan Financial
                                  Group, Inc. (holding company) and Chairman and
                                  Chief Executive Officer of NCM Capital
                                  Management Group, Inc. (investment company),
                                  Durham, NC.

                                  Director,  SCANA  Corporation,  Columbia,  SC;
                                  PSNC,  Gastonia,  NC; M&F Bankcorp,  Inc., and
                                  Its  subsidiary,  Mechanics  and Farmers Bank,
                                  Durham, NC; NetDirect, Minneapolis, MN., and

                                  Trustee  of   Teachers   Insurance   Annuity
                                  Association  -  College  Retirement  Equity
                                  Fund (TIAA- CREF).

     Harold C. Stowe       54     Since March 1997, President and Chief
         (1999)                   Executive  Officer of Canal Industries, Inc.,
                                  Conway, SC (forest products industry).

                                  From 1996 to March 1997, Co-President of Canal
                                  Industries, Inc.

                                  From 1991 to 1996, Executive Vice President of
                                  CSI  Group,   Inc.,   a   division   of  Canal
                                  Industries, Inc.

                                  Director, SCANA Corporation, Columbia, SC;
                                  PSNC, Gastonia, NC; Canal Industries, Inc.,
                                 Conway, SC; Ruddick Corporation, Charlotte, NC.

  William B. Timmerman     54     Since March 1, 1997, Chairman and Chief
         (1991)                   Executive Officer of SCANA Corporation,
                                  Columbia, SC.

                                  From at least  March  1,  1996,  President  of
                                  SCANA Corporation.

                                  From August 21,  1996 to March 1, 1997,  Chief
                                  Operating   Officer   of  SCANA   Corporation.
                                  Director,  SCANA  Corporation,  Columbia,  SC;
                                  PSNC,  Gastonia,  NC;  Powertel,   Inc.,  West
                                  Point, GA; ITC^DeltaCom,  Inc. West Point, GA;
                                  The Liberty Corporation, Greenville, SC.

      G. Smedes York 60 For more than five years,  President and (2000) Raleigh,
         NC.Treasurer of York Properties, Inc.
                                  (full-service commercial and residential real
                                  estate company).


                                  Director,  SCANA  Corporation,  Columbia,  SC;
                                  PSNC, Gastonia, NC.

 Charles E. Zeigler, Jr.   54     Since February 2000, President and Chief
         (2000)                   Operating Officer of PSNC, Gastonia, NC.

                                  From February 1993 to February 2000, Chairman,
                                  President and Chief Executive Officer of
                                  PSNC.

                                  Director,  SCANA  Corporation,  Columbia,  SC;
                                  PSNC, Gastonia, NC.





<PAGE>


<TABLE>


                           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>        <C>                                                          <C>
W. B. Timmerman    54         Chairman of the Board and Chief Executive Officer            1997-present
                               President, SCANA                                            *-present
                              Chief Operating Officer, SCANA                               1996-1997
                              President, SCI, an affiliate                                 1996-1997
                              Chief Financial Officer and Controller, SCANA                *-1996

H. T. Arthur       55         Senior Vice President and General Counsel                    1998-present
                              Vice President and General Counsel                           1996-1998

N. O. Lorick       50         President and Chief Operating Officer                        2000-present
                              Vice President of Fossil and Hydro Operations                *-2000

K. B. Marsh        45         Senior Vice President - Finance and Chief Financial
                                  Officer                                                  2000-present
                              Senior Vice President - Finance, Chief Financial Officer
                                and Controller, SCANA                                      1998-2000
                              Vice President - Finance, Chief Financial Officer and
                                Controller, SCANA                                          1996-1998
                              Vice President - Finance, Treasurer and Secretary, SCE&G     *-1996

S. A. Byrne        40         Vice President Nuclear Operations                            2000-present
                              General Manager Nuclear Plant Operations                     *-2000

M. R. Cannon       50         Controller, SCANA & All Subsidiaries (excluding SEMI)        2000-present
                              Treasurer, SCANA & SCE&G                                     *-2000

*Indicates position held at least since March 1, 1996

</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 executive officers. Based solely on a review of the copies of such
forms and  amendments  furnished to SCE&G and written  representations  from the
executive  officers and  directors,  SCE&G believes that during 2000 all Section
16(a) filing requirements  applicable to its executive  officers,  directors and
greater than 10 percent beneficial owners were complied with.



<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 2001 annual meeting
of shareholders.
<TABLE>

SCE&G:  The information  called for by Item 11,  Executive  Compensation,  is as
follows:

                           Summary Compensation Table

                                                  Annual Compensation                      Long-Term Compensation Awards
                                                                                     Securities
                                                                                     Underlying
                                                                                       Option        LTIP
                                        Salary       Bonus(1)     Compensation(2)       SARS      Payouts(3)   Compensation(4)
Name and Principal Position   Year        ($)           ($)             ($)             (#)          ($)             ($)
                              ----


<S>                           <C>     <C>             <C>             <C>              <C>                         <C>
W. B. Timmerman               2000    524,261(5)      354,486         17,888           35,620         -            50,230
Chairman, President and
Chief                         1999      490,313       312,900         17,212                  -    298,813         29,419

Executive Officer - SCANA     1998      455,909       303,780         17,514                  -       -            27,138


J. L. Skolds                 2000        244,086         -            12,878                  -       -            24,743
Former President and Chief   1999        330,665      168,288         16,232                  -    150,618         19,840

Operating Officer - SCE&G    1998        305,123      163,399         14,099                  -       -            18,201


N. O. Lorick                 2000        167,778      124,921           7,313           2,332         -            12,728
President and Chief
Operating                    1999        157,417       44,356           7,313                 -      38,754          9,445

Officer - SCE&G              1998        143,492       46,719           4,813                 -       -              8,613


K. B. Marsh                  2000       276,172       150,720         10,613           11,627         -            24,254
Senior Vice President -
Finance                      1999       241,354       128,058         10,337                  -      81,555        14,481
and Chief Financial
Officer -                    1998       219,860        99,372          8,654                  -       -            13,122
SCANA


H. T. Arthur                 2000       234,812       120,480         16,119            8,796         -            19,718
Senior Vice President and    1999       219,806        93,825         15,939                  -       65,843       13,188

General Counsel              1998       203,162        99,372          9,534                  -       -            12,190


S. A. Byrne                  2000       183,555       123,492          8,310            8,796         -            12,962

Vice President Nuclear       1999       137,321         32,483         3,600                  -       -              8,239

Operations                   1998       125,458         38,682         2,100                  -       -              7,528



(1) Payments under the Annual Incentive Plan.
(2) For 2000, other annual compensation consists of automobile  allowance,  life
    insurance  premiums  on  policies  owned by  named  executive  officers  and
    payments to cover  taxes on  benefits  of $9,000,  $7,435 and $1,453 for Mr.
    Timmerman;  $6,000, $6,878 and $0 for Mr. Skolds;  $6,000, $1,313 and $0 for
    Mr. Lorick;  $9,000, $1,183 and $430 for Mr. Marsh; $9,000, $6,830, and $289
    for Mr. Arthur and $8,100, $0 and $210 for Mr. Byrne.
(3)  Payments  under  the  Long-term  Equity  Compensation  Plan.  (4) All other
compensation for all named executive officers consists solely of
    contributions to defined contribution plans. (5) Reflects actual salary paid
    in 2000. Base salary of $537,100, became effective on May 1, 2000.
(6) Mr. Skolds resigned from SCE&G on August 18, 2000.
</TABLE>

<PAGE>

<TABLE>


Options Grants and Related Information
                                          Options/SAR Grants in Last Fiscal Year

                                                                                                  Potential
                                                                                             Realizable Value at
                                                                                                Assumed Annual
                                                                                             Rates of Stock Price
                                                                                                 Appreciation
                                   Individual Grants                                           for Option Term
----------------------------------------------------------------------------------------- ---------------------------



         (a)                 (b)              (c)              (d)             (e)             (f)           (g)

                          Number of       % of Total
                          Securities       Options/
                          Underlying         SARs
                           Options/       Granted to       Exercise or
                             SARs        Employees in      Base Price       Expiration
Name                       Granted        Fiscal Year        ($/Sh)            Date           5% ($)        10%($)
----------------------- --------------- ---------------- ---------------- --------------- --------------- -----------

<S>                         <C>              <C>              <C>            <C>   <C>       <C>          <C>
W. B. Timmerman             35,620           22.20            25.50          04/27/10        571,345      1,447,597
N. O. Lorick                  2,332           1.45            25.50          04/27/10          37,405       94,772
K. B. Marsh                 11,627            7.25            25.50          04/27/10        186,497         472,521
H. T. Arthur                 8,796            5.48            25.50          04/27/10        141,088         357,469
S. A. Byrne                  8,796            5.48            25.50          04/27/10        141,088         357,469

All the above options vest 33 1/3 percent on each of the first, second and third
anniversaries of the date of the grant, April 27, 2000.


                  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>
W. B. Timmerman                                       0/35,620                               0/144,724
N. O. Lorick                                           0/2,332                                 0/9,475
K. B. Marsh                                           0/11,627                                0/47,240
H. T. Arthur                                           0/8,796                                0/35,738
S. A. Byrne                                            0/8,796                                0/35,738

(1)Based on the closing  price of $29.5625 per share on December  29, 2000,  the
last trading date of the fiscal year.

</TABLE>

<PAGE>



The  following  table  lists  the  performance  share  awards  made in 2000 (for
potential  payment in 2003) 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>
                                           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             12,510          2000-2002             5,004             12,510              18,765
N. O. Lorick                 3,390          2000-2002             1,356               3,390              5,085
K. B. Marsh                  4,880          2000-2002             1,952               4,880              7,320
H. T. Arthur                 3,410          2000-2002             1,364               3,410              5,115
S. A. Byrne                  3,410          2000-2002             1,364               3,410              5,115

</TABLE>

         Payouts  occur  when  SCANA's  Total  Shareholder  Return is in the top
two-thirds of the Long-Term Equity  Compensation  Plan peer group, and will vary
based on SCANA's  ranking  against the peer  group.  Executives  earn  threshold
payouts at the 33rd percentile of three-year performance. Target payouts will be
made at the 50th percentile of three-year  performance.  Maximum payouts will be
made when  performance  is at or above the 75th  percentile  of the peer  group.
Payments will be made on a sliding scale for performance  between  threshold and
target and target and maximum.  No payouts will be earned if  performance  is at
less than the 33rd  percentile.  Awards are designated as target shares of SCANA
Common Stock and may be paid in stock or a combination of stock and cash.

DEFINED BENEFIT PLANS

         Effective January 1, 2000, the SCANA Corporation Retirement Plan, a tax
qualified  defined benefit plan, was amended to provide a mandatory cash balance
benefit  formula (the "Cash Balance  Formula")  for employees  hired on or after
that date.  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 a cash balance benefit option.

         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 equals 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 rate for 30-year  Treasuries  for  December of the
previous  calendar year.  Compensation  credits equal 5 percent of  compensation
under the Social  Security Wage Base and 10 percent of compensation in excess of
the Social Security Wage Base.

         In  addition  to its  Retirement  Plan  for all  employees,  SCANA  has
Supplemental   Executive   Retirement   Plans  ("SERPs")  for  certain  eligible
employees, including certain officers of its subsidiaries. A SERP is an unfunded
plan that  provides for benefit  payments in addition to benefits  payable under
the  qualified  Retirement  Plan  so as to  make  up for  benefits  lost  in the
Retirement Plan because of Internal Revenue Code maximum benefit limitations.

         All the executive officers named in the Summary  Compensation Table are
participating  under the cash balance  benefit option of the plan. The estimated
annual retirement  benefits payable as life annuities at age 65 under the plans,
based on projected  compensation  (assuming increases of 4 percent per year), to
the executive  officers named in the Summary  Compensation Table are as follows:
Mr. Timmerman - $410,496; Mr. Lorick - $224,448; Mr. Marsh - $ 278,220; Mr.
Arthur - $122,424 and Mr. Byrne - $158,258.

         SCANA has a Key Employee  Retention Plan ("KERP") covering officers and
certain other executive employees of SCE&G that provide supplemental  retirement
or death benefits for participants.  These employees also participate in SCANA's
Retirement Plan.

         Participants  who  elected  to  remain in the  final  average  pay plan
continue to  participate  in the KERP under the provisions in effect on June 30,
2000.  Each  participant  who elected to convert to the cash balance plan became
entitled  on July 1,  2000 to a KERP cash  balance  benefit.  The  amount of the
benefit  was  determined  by  discounting  to June 30,  2000 the  amount  of the
participant's  projected  retirement benefit under the prior plan,  assuming the
participant retired upon attaining the earlier of (i) age 65 or (ii) 35 years of
service (unreduced  retirement age), adjusted to reflect actual years of service
through June 30, 2000.

         Each  participant's  account  balance will increase in each  subsequent
year until  unreduced  retirement  age by (i)  interest  at the rate for 30-year
Treasuries and (ii) an accrual  reflecting one additional year of service.  If a
participant  continues  to work beyond his  unreduced  retirement  age, his KERP
account will only grow with interest.

         In the event of the participant's death prior to such retirement, SCANA
will pay to the participant's  designated  beneficiary,  the participant's  KERP
account balance at the time of death. In the event a participant's employment is
terminated  prior to retirement,  the participant  will be paid his KERP account
balance.

         The estimated  annual  retirement  benefits payable at age 65 under the
KERP to the executive  officers  named in the Summary  Compensation  Table,  who
participate  in the KERP,  based on projected  eligible  compensation  (assuming
increases  of 4 percent per year) are:  Mr.  Timmerman - $ 186,357;  Mr. Marsh -
$146,464; Mr. Arthur - $80,086; Mr. Lorick - $84,677 and Mr. Byrne - $120,183.

         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 is
used to  receive  SCANA  contributions  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).

         (1) SCANA Corporation  Supplementary  Voluntary Deferral Plan (2) SCANA
         Corporation   Key  Employee   Retention  Plan  (3)  SCANA   Corporation
         Supplemental  Executive Retirement Plan (4) SCANA Corporation Long-term
         Equity Compensation Plan (5) SCANA Corporation Annual Incentive Plan
(6)      SCANA Corporation Key Executive Severance Benefits Plan
(7)      SCANA Corporation Supplementary Key Executive Severance Benefits Plan

         The trusts and the plans provide  flexibility to SCANA in responding to
a Potential  Change in Control (as defined in the trust)  depending upon whether
the Change in Control  would be viewed as being  "hostile" or  "friendly."  This
flexibility  includes the ability to deposit and withdraw SCANA contributions up
to the  point  of a  Change  in  Control,  and to  affect  the  number  of  plan
participants who may be eligible for benefit distributions upon, or following, a
Change in Control.


<PAGE>




         The Key  Executive  Severance  Benefits  Plan is operative as a "single
trigger"  plan,  meaning  that  upon the  occurrence  of a  "hostile"  Change in
Control,   benefits  provided  under  Plans  (1)  through  (5)  above  would  be
distributed  in a  lump  sum.  In  contrast,  the  Supplementary  Key  Executive
Severance  Benefits  Plan is  operative  for a period of 24 months  following  a
Change in Control which prior to its  occurrence is viewed as being  "friendly."
In this circumstance,  the Key Executive Severance Benefits Plan is inoperative.
The  Supplementary Key Executive  Severance  Benefits Plan is a "double trigger"
plan that would pay benefits in lieu of those otherwise provided under Plans (1)
through (5) in either of two  circumstances:  (a) the participant's  involuntary
termination  of  employment  without  "Just  Cause",  or (b)  the  participant's
voluntary  termination  of  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,  will be grossed up to include
estimated federal,  state and local income taxes and any applicable excise taxes
owed by plan participants on those benefits.

         The benefit  distributions  under the Key Executive  Severance Benefits
Plan would include the following:

o       An amount equal to three times the sum of: (1) the officer's annual base
        salary in effect as of the Change in  Control  and (2) the larger of (i)
        the  officer's  target award in effect as of the Change in Control under
        the Annual Incentive Plan or (ii) the officer's average of actual annual
        incentive bonuses received during the prior three years under the Annual
        Incentive Plan.

o       An amount equal to the projected  cost for coverage for three full years
        following  the Change in Control as though the officer had  continued to
        be  a  SCANA  employee  with  respect  to  medical  coverage,  long-term
        disability  coverage  and  either  Life Plus (a special  life  insurance
        program  combining  whole  life and term  coverages)  or group term life
        coverage in accordance with the officer's  election,  in each case so as
        to provide  substantially the same level of coverage and benefits as the
        officer enjoyed as of the date of the Change in Control.

o       A benefit  distribution under the Supplementary  Voluntary Deferral Plan
        calculated  to include  any  implied  dividends  accrued  under the plan
        through the date of the Change in Control.

o       A benefit  distribution  under the Key Employee  Retention Plan equal to
        the lump sum  amount  calculated  as of the day of the Change in Control
        under the KERP cash balance formula.

o       A benefit distribution under the Supplemental  Executive Retirement Plan
        ("SERP") equal to the amount of the SERP cash balance  account as of the
        date  of  the  Change  in  Control,  increased  by an  amount  equal  to
        additional compensation and interest credits, assuming the executive had
        completed  three  additional  years of service with  compensation at the
        participant's rate of compensation then in effect, and assuming interest
        credits for three  additional  years at the applicable rate of interest,
        which benefit  would then be reduced by the amount of the  participant's
        cash balance  account  accrued under the Retirement  Plan as of the date
        the Change in Control.

o       A benefit  distribution  under the  Performance  Share Plan equal to 100
        percent of the targeted awards for all performance periods not completed
        as of the date of the Change in Control.

o       A benefit  distribution  under the Long-Term  Equity  Compensation  Plan
        equal to 100 percent of the  targeted  performance  share awards for all
        performance  periods  not  completed  as of the  date of the  Change  in
        Control.

o       Under the Long-Term Equity  Compensation  Plan, all  nonqualified  stock
        options  awarded  shall  become   immediately   exercisable  and  remain
        exercisable throughout their term.

o       A benefit  distribution  under the  Annual  Incentive  Plan equal to 100
        percent  of the  target  award in effect as of the date of the Change in
        Control.

         Benefits under the Supplementary Key Employee  Severance  Benefits Plan
would be the same except that the  benefits  under the  Supplementary  Voluntary
Deferral Plan would be increased by implied interest from the date of the Change
in Control  until the end of the month  preceding the month in which the benefit
is distributed.



<PAGE>



COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

         During 2000,  decisions on various  elements of executive  compensation
were made by the Management  Development and Corporate Performance Committee and
the Long-Term Equity Compensation Plan Committee. No officer, employee or former
officer of SCANA or any of its subsidiaries served as a member of the Management
Development  and  Corporate   Performance  Committee  or  the  Long-Term  Equity
Compensation Plan Committee except Mr.  Timmerman,  who served as an ex-officio,
non-voting  member  of the  Management  Development  and  Corporate  Performance
Committee.

         The names of the persons who serve on the  Management  Development  and
Corporate  Performance  Committee and the  Long-Term  Equity  Compensation  Plan
Committee  can be found at Item 12,  Security  Ownership  of Certain  Beneficial
Owners  and  Management.  Although  Mr.  Timmerman  served  as a  member  of the
Management  Development  and  Corporate  Performance   Committee,   he  did  not
participate in any of its decisions concerning executive officer compensation.

         During  2000,  SCANA  and  its  subsidiaries   engaged  in  a  business
transaction  with an entity  with  which Mr.  Amick (a member of the  Management
Development  and  Corporate  Performance  Committee)  is related.  Mr.  Amick is
President and a 20 percent owner of Team Amick  Motorsports LLC, a business that
owns and operates a NASCAR  sanctioned  racing car. This car participates in the
Busch Grand National Racing Series. During 2000, SCANA and its subsidiaries paid
Team Amick  Motorsports,  LLC a total of  $254,085,  for a  sponsorship  and car
appearances  pursuant  to  which  SCANA  received   promotional   considerations
associated  with  NASCAR  racing.  SCANA  and its  subsidiaries  do not  plan to
continue as a sponsor with Team Amick Motorsports, LLC in 2001.

Directors Compensation

Board Fees

         Officers  of SCANA who are also  directors  do not  receive  additional
compensation  for their service as directors.  Since July 1, 2000,  compensation
for non-employee directors of SCANA has included the following:

o  an annual retainer of $30,000 (60 percent of the annual retainer fee is paid
     in shares of SCANA Common Stock);
o  $3,500 for each board meeting attended;
o    $3,000 for  attendance  at a committee  meeting  held on a day other than a
     regular meeting of the Board;
o $250 for  participation  in a  telephone  conference  meeting;  o  $2,000  for
attendance at an all-day  conference;  and o reimbursement for expenses incurred
in connection with all of the above.

Director Compensation and Deferral Plans

         During  2000,  non-employee  directors  could  participate  in  SCANA's
Voluntary  Deferral Plan.  This plan permitted  non-employee  directors to defer
receipt of all or part of their fees (except the portion paid in shares of SCANA
Common Stock) and receive, upon ceasing to serve as a director,  the amount that
would have resulted from investing the deferred  amounts in an interest  bearing
savings account.

         During calendar year 2000, Mr. Bennett deferred  compensation under the
Voluntary Deferral Plan and his account was credited with interest in the amount
of $2,669 for that year.

         Effective January 1, 2001, non-employee director compensation deferrals
are governed by a new plan,  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.


<PAGE>



         Under the new plan,  a director  may elect to defer (i) 100  percent of
all  compensation  amounts , or (ii) the 60 percent of the annual  retainer  fee
required to be paid in SCANA Common Stock, in a hypothetical investment in SCANA
Common Stock, with distribution from the plan to be ultimately payable in actual
shares of SCANA Common Stock.  A director also may elect to defer the 40 percent
of the annual  retainer  fee not  required to be paid in shares of SCANA  Common
Stock and up to 100  percent  of meeting  attendance  and  conference  fees with
distribution from the plan to be ultimately payable in either SCANA Common Stock
or cash.  Amounts  payable in SCANA  Common  Stock  accrue  earnings  during the
deferral period at SCANA's dividend rate, which amount may be elected to be paid
in cash when  accrued  or  retained  to invest in  hypothetical  shares of SCANA
Common Stock. Amounts payable in cash accrue interest earnings until paid.

         For calendar year 2001, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan,
Stowe  and York and Ms.  Miller  have  elected  to defer  100  percent  of their
compensation under the Director  Compensation and Deferral Plan so as to acquire
hypothetical  shares of SCANA Common Stock. In addition,  Mr. Hagood has elected
to defer 60 percent of his annual  retainer  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  designated by the
director. The plan is intended to reinforce SCANA's commitment to quality higher
education  and to enhance  its  ability to attract  and retain  qualified  board
members.  A portion is  contributed  upon  retirement  of the  director  and the
remainder  upon  the  director's  death.  The  plan is  funded  in part  through
insurance on the lives of the directors.  Designated  in-state  institutions  of
higher  education must be approved by the Chief Executive  Officer of SCANA. Any
out-of-state  designation  must be approved by the  Management  Development  and
Corporate Performance Committee.  The designated institutions are reviewed on an
annual basis by the Chief Executive Officer to assure compliance with the intent
of the program.

Other

     As a Company retiree, Mr. Gressette receives monthly retirement benefits of
$39,571.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

SCANA:  The  information  called for by Item 12,  Security  Ownership of Certain
Beneficial  Owners and  Management  is  incorporated  herein by reference to the
caption  "Share  Ownership of Directors,  Nominees and  Executive  Officers" and
"Five Percent Owner of SCANA Common Stock" in SCANA's definitive proxy statement
for the 2001 annual meeting of shareholders.

SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table lists shares of SCANA common stock  beneficially  owned on March
9, 2001 by each director,  each nominee and each executive  officer named in the
Summary Compensation table on page 141. <TABLE>

                        SECURITY OWNERSHIP OF MANAGEMENT

                      Amount and Nature                                    Amount and Nature
                      of Beneficial Ownership of                           of Beneficial Ownership of
                      SCANA Common Stock *(1)(2)(3)(4)                      SCANA Common Stock *(1)(2)(3)(4)
Name                                                       Name
-----                 ------------------------------       ----

<S>        <C>                   <C>                                                   <C>
B. L. Amick(5)                   11,821               W. H. Hipp                       4,896
H. T. Arthur                     16,211               K. B. Marsh                     18,826
J. A. Bennett(6)                  2,210               L. M. Miller(6)                  3,356
W. B. Bookhart, Jr.(5)(6)        21,811               N. O. Lorick                    15,977
W. C. Burkhardt(5)(6)            11,130               M. K. Sloan(5)(6)                3,955
S. A. Byrne                       7,467               H. C. Stowe(5)(6)                3,941
H. M. Chapman(5)(6)               7,994               W. B. Timmerman(5)              65,191
E. T. Freeman                     6,435               G. S. York(6)                   10,744
L. M. Gressette, Jr.             63,640               C. E. Zeigler, Jr.              32,133
D. M. Hagood(6)                     820
*Each of the directors,  nominees and named executive  officers owns less than 1
percent of the shares outstanding.
</TABLE>

All directors and executive  officers as a group ( persons) TOTAL .TOTAL PERCENT
OF CLASS, outstanding and entitled to vote at the Annual Meeting of Shareholders
percent.----------

(1) Includes shares owned by close relatives,  the beneficial ownership of which
    is disclaimed  by the  director,  nominee or named  executive  officers,  as
    follows: Mr. Amick-480; Mr. Bookhart-5,804; Mr. Gressette-1,060;  and by all
    directors, nominees and executive officers 7,344 in total.
(2) Includes shares  purchased  through  February 28, 2001, 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 March 9, 2001, each of Messrs. Amick, Bennett, Burkhardt,
    Hipp,  Sloan,  Stowe and York and Ms.  Miller had acquired 674  hypothetical
    shares under the plan and Mr. Hagood had acquired 404.
(4) Includes shares subject to options exercisable within 60 days.
(5) Serves on The Management Development and Corporate Performance Committee
    (Mr.  Timmerman  serves as an ex-officio,  non-voting member).
(6) Serves on the Long-Term Equity Compensation Plan Committee.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

SCANA: The information called for by Item 13, Certain  Relationships and Related
Transactions is incorporated  herein by reference to the captions  "Compensation
Committee  Interlocks and Insider  Participation" and "Related  Transactions" in
SCANA's definitive proxy statement for the 2001 annual meeting of stockholders.

       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 2001
annual meeting of  shareholders  shall not be incorporated by reference into any
such filings.

SCE&G: For information regarding certain relationships and related transactions,
see Item 11, Executive  Compensation  under the heading  Compensation  Committee
Interlocks and Insider Participation and the following:

        During 2000, SCANA paid $239,242  (including the value of non-utility in
kind services  provided by SCANA) to  subsidiaries  of Liberty  Corporation  for
advertising  expenses.  Mr. Hipp is the Chairman,  President and Chief Executive
Officer and a director of Liberty  Corporation.  It is anticipated  that similar
transactions will occur in the future.



<PAGE>



                                     PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The  following  documents  are  filed as a part of this  report on this Form
10-K:

             (1)  Financial Statements and Schedules:

                    The   Independent   Auditor's   Reports  on  the   financial
                    statements for SCANA, SCE&G and PSNC are listed under Item 8
                    herein.

                    The financial  statements and  supplementary  financial data
                    filed as part of this  report for SCANA,  SCE&G and PSNC are
                    listed under Item 8 herein.

                    The  Financial  Statement  Schedules  filed  as part of this
                    report for SCANA,  SCE&G and PSNC are  listed  beginning  on
                    page 150.

             (2) Exhibits

                    Exhibits  required  to be filed with this  Annual  Report on
                    Form 10-K are  listed in the  Exhibit  Index  following  the
                    signature   page.   Certain  of  such  exhibits  which  have
                    heretofore  been  filed  with the  Securities  and  Exchange
                    Commission  and which are  designated  by reference to their
                    exhibit number in prior filings are  incorporated  herein by
                    reference and made a part hereof.

                    Pursuant to rule  15d-21  promulgated  under the  Securities
                    Exchange Act of 1934, the annual report for SCANA's employee
                    stock  purchase  plan will be furnished  under cover of Form
                    10-K/A  to  the  Commission  when  the  information  becomes
                    available.

                    As permitted under Item 601(b)(4)(iii), instruments defining
                    the  rights of  holders  of  long-term  debt of less than 10
                    percent  of the total  consolidated  assets  of  SCANA,  for
                    itself and its  subsidiaries,  of SCE&G,  for itself and its
                    subsidiaries,  and of PSNC, for itself and its subsidiaries,
                    have been omitted and SCANA, SCE&G and PSNC agree to furnish
                    a copy of such instruments to the Commission upon request.

(b) Reports on Form 8-K during the fourth  quarter of 2000 for SCANA,  SCE&G and
PSNC:

             None




<PAGE>


<TABLE>

SCANA:

Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2000, 1999 and 1998.

For December 31, 2000                                              Additions
                                                                           Charged to
                                          Beginning       Charged to         Other         Deductions         Ending
Description                                Balance          Income          Accounts      from Reserves       Balance
-------------------------------------- ---------------- ---------------- --------------- ---------------- ----------------

Reserves deducted from related assets on the balance sheet:

Uncollectible accounts
<S>             <C>                       <C>             <C>                                    <C>        <C>
                2000                      7,302,273       23,308,561           -                 77,133     30,533,701
                1999                      1,965,732         5,636,123          -               299,582        7,302,273
                1998                      1,807,047           184,257          -                25,572        1,965,732

Reserve for investment impairment
                2000                       4,133,768       1,000,000           -               205,000        4,928,768

                1999                     10,292,611            -               -            6,158,843         4,133,768

                1998                     11,150,060            -               -               857,449      10,292,611

Reserves other than those deducted from assets on the balance sheet:


Reserve for injuries and damages
                2000                      5,221,544        2,461,339           -               333,544       7,349,339
<S>             <C>                       <C>              <C>                                 <C>           <C>
                1999                      4,287,986        1,352,448           -               418,890       5,221,544
                1998                      4,187,594           461,462          -               361,070       4,287,986

Provision for pension and benefit
   Staff Reduction Plan
                2000                      6,487,365                   -        -               131,570       6,355,795

<S>             <C>                       <C>                <C>                                             <C>
                1999                      6,256,249          231,116           -                -            6,487,365
                1998                      4,486,895        6,256,249           -            4,486,895        6,256,249

Provision for environmental
   remediation and settlement
                2000                      3,223,821                   -        -               409,252       2,814,569
                1999                      3,619,572                   -        -               395,751       3,223,821

                1998                      4,006,562            -               -               386,990       3,619,572





<PAGE>


</TABLE>



SCE&G:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2000, 1999 and 1998.
<TABLE>

For December 31, 2000                                              Additions
                                          Beginning       Charged to       Charged to      Deductions         Ending
Description                                Balance          Income       Other Accounts   From Reserves       Balance
-------------------------------------- ---------------- ---------------- --------------- ---------------- ----------------

Reserves deducted from related assets on the balance sheet:

Uncollectible accounts
<S>             <C>                        <C>              <C>                                <C>            <C>
                2000                       537,000          116,000            -               76,000         577,000
                1999                       611,001            80,000                          154,001         537,000
                1998                       611,001                   -         -                      -       611,001

Reserves other than those deducted from assets on the balance sheet:

Reserve for injuries and damages
                2000                      3,972,816         819,431            -              217,055        4,575,192
                1999                      4,176,794         104,000            -              307,978        3,972,816
                1998                      4,039,148         460,462            -              322,816        4,176,794


Provision for pension and benefit
   Staff Reduction Plan
                2000                                 -              -          -                       -               -
                1999                                 -              -          -                       -               -
                1998                      4,486,895                 -          -            4,486,895                  -

Provision for environmental
   remediation and settlement
                2000                      3,223,821                 -          -              409,252        2,814,569
                1999                      3,619,572                -           -              395,751        3,223,821
                1998                      4,006,562                -           -              386,990        3,619,572
</TABLE>



<PAGE>




<TABLE>


PSNC:
Schedule II - Valuation and Qualifying  Accounts for the Year Ended December 31,
2000,  Three Months Ended December 31, 1999 and Fiscal Years Ended September 30,
1999 and 1998.

For December 31, 2000                                              Additions
                                       Beginning          Charged to       Charged to      Deductions         Ending
Description                             Balance             Income       Other Accounts   from Reserves       Balance
-------------------------------- ---------------------- ---------------- --------------- ---------------- ----------------

Reserves deducted from related assets on the balance sheet:

Uncollectible accounts
<S>                        <C>         <C>                 <C>                              <C>              <C>
                           2000        2,702,014           2,417,566           -            2,716,884        2,402,696
              Three Months 1999        1,737,815              470,895          -              (199,069)       2,702,014*
               Fiscal Year 1999        2,086,128             725,094           -            1,073,407        1,737,815
               Fiscal Year 1998        2,521,983             866,786           -            1,302,641        2,086,128

Reserves other than those deducted from assets on the balance sheet:

Reserve for injuries and
damages
                           2000        2,197,615             494,629           -            1,065,986        1,626,258
              Three Months 1999        1,930,377              442,000          -             174,762         2,197,615
               Fiscal Year 1999        1,207,278           1,802,544           -            1,079,445        1,930,377
               Fiscal Year 1998        1,131,780           1,422,271           -            1,346,773        1,207,278

Provision for post-retirement &
   post-employment
                           2000        6,658,753           1,227,823           -            7,488,576          398,000
              Three Months 1999        6,466,563             298,857           -              106,667        6,658,753
               Fiscal Year 1999        5,165,324           1,676,767           -              375,528        6,466,563
               Fiscal Year 1998        4,436,674           1,052,990           -              324,340        5,165,324

</TABLE>

*Ending balance for December 31, 1999 includes  $294,235  uncollectible  reserve
balance for SCANA Public Service Company, L.L.C. (formerly Sonat Public Service)
purchased December 31, 1999.


<PAGE>



                                   SIGNATURES

       Pursuant  to the  requirements  of Section 13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned,  thereunto duly authorized.  The signature of the
undersigned  company shall be deemed to relate only to matters having  reference
to such company and any subsidiaries thereof.

                              SCANA CORPORATION


                             s/W. B. Timmerman
By:                          W. B. Timmerman, Chairman of the Board,
                             President, Chief Executive Officer and Director

DATE:                        March 27, 2001


       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the dates indicated.



                       s/W. B. Timmerman
                       W. B. Timmerman, Chairman of the Board, President,
                       Chief Executive Officer and Director
                       (Principal Executive Officer)



                       s/K. B. Marsh
                       K. B. Marsh, Senior Vice President - Finance,
                       Chief Financial Officer
                       (Principal Financial  Officer)



                       s/ M. R. Cannon
                       M. R. Cannon,
                       Controller
                       (Principal Accounting Officer)

                               Other Directors*:

              B. L. Amick                         D. M. Hagood
              J. A. Bennett                       W. H. Hipp
              W. B. Bookhart, Jr.                 L. M. Miller
              W. C. Burkhardt                     M. K. Sloan
              H. M. Chapman                       H. C. Stowe
              E. T. Freeman                       G. S. York
              L. M. Gressette, Jr.                C. E. Zeigler, Jr.

*Signed on behalf of each of these persons by ,                 Attorney-in-Fact



DATE:                               March 27, 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.

                            SOUTH CAROLINA ELECTRIC & GAS COMPANY



By:                         s/N. O. Lorick
                            N. O. Lorick, President and Chief
                            Operating Officer


Date:                       March 27, 2001




       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the dates indicated.




                         s/W. B. Timmerman
                         W. B. Timmerman, Chairman of the Board,
                         Chief Executive Officer and Director
                         (Principal Executive Officer)



                         s/K. B. Marsh
                         K. B. Marsh, Senior Vice President - Finance and
                         Chief Financial Officer
                         (Principal Financial Officer)



                          s/ M. R. Cannon
                          M. R. Cannon,
                          Controller
                          (Principal Accounting Officer)

                                  Other Directors*:

                    B. L. Amick                   D. M. Hagood
                    J. A. Bennett                 W. H. Hipp
                    W. B. Bookhart, Jr.           L. M. Miller
                    W. C. Burkhardt               M. K. Sloan
                    H. M. Chapman                 H. C. Stowe
                    E. T. Freeman                 G. S. York
                    L. M. Gressette, Jr.          C. E. Zeigler, Jr.

*Signed on behalf of each of these persons by                , Attorney-in-Fact


Date:                               March 27, 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.


                  PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED



By:                         s/C. E. Zeigler, Jr.
                            C. E. Zeigler, Jr., President and Chief
                            Operating Officer

Date:                       March 27, 2001


       Pursuant to the requirements of the Securities Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the dates indicated.




                           s/W. B. Timmerman
                           W. B. Timmerman, Chairman of the Board,
                           Chief Executive Officer and Director
                           (Principal Executive Officer)



                           s/K. B. Marsh
                           K. B. Marsh, Senior Vice President - Finance and
                           Chief Financial Officer
                           (Principal Financial Officer)


                           s/ M. R. Cannon
                           M. R. Cannon,
                           Controller
                           (Principal Accounting Officer)


                                  Other Directors*:

                B. L. Amick                          D. M. Hagood
                J. A. Bennett                        W. H. Hipp
                W. B. Bookhart, Jr.                  L. M. Miller
                W. C. Burkhardt                      M. K. Sloan
                H. M. Chapman                        H. C. Stowe
                E. T. Freeman                        G. S. York
                L. M. Gressette, Jr.                 C. E. Zeigler, Jr.


*Signed on behalf of each of these persons by                , Attorney-in-Fact



Date:                               March 27, 2001



<PAGE>



                                  EXHIBIT INDEX

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


                       Agreement  and Plan of Merger,  dated as of February  16,
                       1999 as amended and restated as of May 10,  1999,  by and
                       among   Public   Service   Company  of  North   Carolina,
                       Incorporated, SCANA
                        Corporation, New Sub I, Inc. and
                        New Sub II, Inc.(Filed as Exhibit
                        2.1 to Registration Statement No.
                            333-78227 on Form S-4 and
2.01             X                    X      incorporated by reference herein)

                       Restated Articles of Incorporation
                        of SCANA as adopted on April 26,
                          1989 (Filed as Exhibit 3-A to
                       Registration Statement No. 33-49145
                          and incorporated by reference
3.01             X                           herein)

                       Restated Articles of Incorporation
                        of SCE&G, as adopted on December
                       15, 1993 (Filed as Exhibit 3.01 to
                       Registration Statement No.333-8638
                          and incorporated by reference
3.02                        X                herein)

                                             Articles of Amendment of SCANA,
                                             dated April 27, 1995 (Filed as
                                             Exhibit 4-B to Registration
3.03             X                           Statement No. 33-62421 and
                                             incorporated by reference herein)

                         Articles of Amendment of SCE&G,  dated June 7, 1994 and
                        filed June 9, 1994 (Filed as Exhibit 3.02 to
                           Registration Statement No.
                           333-86387 and incorporated
3.04                        X                by reference herein)

                                             Articles of Amendment of SCE&G,
                                             dated November 9, 1994 (Filed as
3.05                        X                Exhibit 3.03 to Registration
                                             Statement No. 333-86387 and
                                             incorporated by reference herein)

                                             Articles of Amendment of SCE&G,
3.06                        X                dated December 9, 1994 (Filed as
                                             Exhibit 3.04 toRegistration
                                             Statement No. 333-86387 and
                                             incorporated by reference herein)

                                             Articles of Correction of SCE&G,
3.07                        X                dated January 17, 1995 (Filed as
                                             Exhibit 3.05 to Registration
                                             Statement No.  333-86387 and
                                             incorporated by reference herein)

                                             Articles of Amendment of SCE&G,
3.08                        X                dated January  13, 1995 (Filed as
                                             Exhibit 3.06 to Registration
                                             Statement No. 333-86387 and
                                             incorporated by reference herein)

                                             Articles of Amendment of SCE&G,
3.09                        X                dated March 30, 1995 (Filed as
                                             Exhibit 3.07 to Registration
                                             Statement No. 333-86387 and
                                             incorporated by reference herein)

                         Articles of Correction of SCE&G
                       Amendment to Statement filed March
                                             30, 1995,  dated  December 13, 1995
                                             (Filed   as    Exhibit    3.08   to
                                             Registration Statement No.
3.10                        X                333-86387 and incorporated by
                                             reference herein)

                                            Articles of Amendment of SCE&G,
3.11                        X               dated December 13, 1995 (Filed as
                                            Exhibit 3.09 to Registration
                                            Statement No. 333-86387 and
                                            incorporated by reference herein)


<PAGE>



                                  EXHIBIT INDEX

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


                                        Articles of Amendment of SCE&G, dated
3.12                X                   February 18, 1997 (Filed as Exhibit 3-L
                                        to Registration Statement No. 333-24919
                                        and incorporated by reference herein)

                                        Articles of Amendment of SCE&G, dated
3.13                X                   February 21, 1997 (Filed as Exhibit 3.1
                                        to Registration Statement No. 333-86387
                                        and incorporated by reference herein)


<PAGE>




                                        Articles of Amendment of SCE&G, dated
                                        April 22, 1997 (Filed as Exhibit 3.12 to
3.14                X                   Registration Statement No. 333-86387 and
                                        incorporated by reference herein)

                                        Articles of Amendment of SCE&G, dated
                                        April 9, 1998 (Filed as Exhibit 3.13 to
3.15                X                   Registration Statement No. 333-86387 and
                                        incorporated by reference herein)

                                        Articles of Amendment of SCE&G, dated
                                        May 19, 1999 (Filed as Exhibit 3.01 to
3.16                X                   Registration Statement No. 333-49960 and
                                        incorporated by reference herein)

                                        Articles of Amendment of SCE&G, dated
                                        August 13, 1999 (Filed as Exhibit 3.02
3.17                X                   to Registration Statement No. 333-49960
                                        and incorporated by reference herein)

                                        Articles of Amendment of SCE&G, dated
                                        March 1, 2000 (Filed as Exhibit 3.03 to
3.18                X                   Registration Statement No. 333-49960 and
                                        incorporated by reference herein)

                                        Articles of Incorporation of PSNC
                                        (formerly New Sub II, Inc.) dated
                                        February 12, 1999 (Filed as Exhibit
                                        3.01 to Registration Statement No.
                                        333-45206 and incorporated by
3.19                            X       reference herein)

                                        Articles of Amendment of PSNC (formerly
                                        New Sub II, Inc.) as adopted on February
                                        10, 2000 (Filed as Exhibit 3.02 to
                                        Registration Statement No. 333-45206 and
3.20                            X       incorporatedby reference herein)

                                        Articles of Correction of PSNC dated
                                        February 11, 2000 (Filed as Exhibit 3.03
3.21                            X       to Registration Statement No. 333-45206
                                        and incorporated by reference herein)

3.22     X                              By-Laws of SCANA as revised and amended
                                        on December 13, 2000 (Filed herewith)

3.23                X                   By-Laws of SCE&G as amended and adopted
                                        on  February 22, 2001  (Filed herewith)

3.24                            X       By-Laws of PSNC as revised and amended
                                        on February 22, 2001 (Filed herewith)


<PAGE>




                                        Articles of Exchange of South Carolina
                                        Electric & Gas Company and SCANA
                                        Corporation (Filed as Exhibit 4-A to
4.01     X          X                   Post-Effective Amendment No. 1 to
                                        Registration Statement No.2-90438
                                        and incorporated by reference herein)


<PAGE>



                                                   EXHIBIT INDEX

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


                                         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
4.02      X                              by reference herein)

                                         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
4.03      X            X                 by reference herein)

                                         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.
4.04      X            X                 2-26459 and incorporated by reference
                                         herein)


<PAGE>


<TABLE>


                                         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
4.05      X            X                 whose file numbers are set forth below and are incorporated by reference herein
<S>                                       <C>                               <C>                  <C>
                                         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



<PAGE>



                                                   EXHIBIT INDEX

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


<S>                                       <C>                        <C>                <C>
                                          December 1, 1980            Exhibit 4-C       to Registration No. 33-38580
                                          April 1, 1981               Exhibit 4-D       to Registration No. 33-49421
                                          June 1, 1981                Exhibit 4-D       to Registration No. 2-73321
                                          March 1, 1982               Exhibit 4-D       to Registration No. 33-49421
                                          April 15, 1982              Exhibit 4-D       to Registration No. 33-49421
                                          May 1, 1982                 Exhibit 4-D       to Registration No. 33-49421
                                          December 1, 1984            Exhibit 4-D       to Registration No. 33-49421
                                          December 1, 1985            Exhibit 4-D       to Registration No. 33-49421
                                          June 1, 1986                Exhibit 4-D       to Registration No. 33-49421
                                          February 1, 1987            Exhibit 4-D       to Registration No. 33-49421
                                          September 1, 1987           Exhibit 4-D       to Registration No. 33-49421
                                          January 1, 1989             Exhibit 4-D       to Registration No. 33-49421
                                          January 1, 1991             Exhibit 4-D       to Registration No. 33-49421
                                          February 1, 1991            Exhibit 4-D       to Registration No. 33-49421
                                          July 15, 1991               Exhibit 4-D       to Registration No. 33-49421
                                          August 15, 1991             Exhibit 4-D       to Registration No. 33-49421
                                          April 1, 1993               Exhibit 4-E       to Registration No. 33-49421
                                          July 1, 1993                Exhibit 4-D       to Registration No. 33-57955
                                          May 1, 1999                 Exhibit 4.04      to Registration No. 333-86387
</TABLE>

                                          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
4.06         X           X                Statement No. 33-49421 and
                                          incorporated by reference herein)

                                          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
4.07         X           X                incorporated by reference herein)

                                          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
4.08         X           X                incorporated by reference herein)

                                          Trust Agreement for SCE&G Trust I
                                          (Filed as Exhibit 4.03 to Registration
4.09         X           X                Statement No. 333-49960 and
                                          incorporated by reference herein)

                                          Certificate of Trust of SCE&G Trust I
                                          (Filed as Exhibit 4.04 to Registration
4.10         X           X                Statement No. 333-49960 and
                                          incorporated by reference herein)

                                          Junior Subordinated Indenture for
                                          SCE&G Trust I (Filed as Exhibit 4.05
4.11         X           X                to Registration Statement No.333-49960
                                           and incorporated by reference herein)

<PAGE>




                                          Guarantee Agreement for SCE&G Trust I
                                          (Filed as Exhibit 4.06 to Registration
4.12         X           X                Statement No. 333-49960 and
                                          incorporated by reference herein)

                                          Amended and Restated Trust Agreement
                                          for SCE&G Trust I (Filed as Exhibit
4.13         X           X                4.07 to Registration Statement No.
                                          333-49960 and incorporated by
                                          reference herein)


<PAGE>



                                                   EXHIBIT INDEX

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


                                       Debenture Purchase Agreement, dated as of
                                       September  15, 1988,  with respect to $25
                                       million  of  10%  Senior  Debentures  due
                                       October 1, 2003 (Filed as Exhibit 4.01 to
4.14     X                     X       Registration Statement No. 333-45206 and
                                       incorporated by reference herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of September 15, 1988, between
                                       PSNC and Southland Life Insurance Company
                                       (Filed as Exhibit 4.02 to Registration
                                       Statement No. 333-45206 and
4.15     X                     X       incorporated by reference herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of September 15, 1988, between
                                       PSNC and Jefferson-Pilot Life Insurance
                                       Company (Filed as Exhibit 4.03 to
                                       Registration Statement No. 333-45206
4.16     X                     X       and incorporated by reference herein)

                                       Amendment to Debenture Purchase Agreemen
                                       dated as of September 15, 1988, between
                                       PSNC and The Franklin Life Insurance
                                       Company  (Filed as Exhibit 4.04 to
                                       Registration Statement No. 333-45206
4.17     X                     X       and incorporated by reference herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of September  15, 1988,  between
                                       PSNC and Columbus Life Insurance  Company
                                       (Filed as  Exhibit  4.05 to Form 10-Q for
                                       the quarter ended September 30, 2000
4.18     X                     X       and incorporated by reference  herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of September  15, 1988,  between
                                       PSNC and  Salkeld  &  Company  (Filed  as
                                       Exhibit 4.06 to Form 10-Q for the quarter
                                       ended September 30, 2000 and
4.19     X                     X       incorporated by reference  herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of September  15, 1988,  between
                                       PSNC and UMB Bank (Filed as Exhibit  4.07
                                       to  Form  10-Q  for  the  quarter   ended
                                       September 30, 2000 and incorporated
4.20     X                     X       by reference herein)

                                       Debenture Purchase Agreement, dated as of
                                       December  5,  1989,   as  amended,   with
                                       respect  to $43  million  of  10%  Senior
                                       Debentures due December 1, 2004 (Filed as
                                       Exhibit 4.05 to
4.21     X                     X       Registration Statement No. 333-45206 and
                                       incorporated by reference herein)

                                       Amendment to Debenture Purchase Agreement
                                       dated as of  December  5,  1989,  between
                                       PSNC and The  Prudential  Life  Insurance
                                       Company of America (Filed as Exhibit 4.06
                                       to
4.22     X                     X       Registration Statement No. 333-45206 and
                                       incorporated by reference herein)

                                       Debenture Purchase Agreement, dated as of
                                       June  25,  1992,   with  respect  to  $32
                                       million of 8.75%  Senior  Debentures  due
                                       June 30, 2012  (Filed as Exhibit  4.07 to
                                       Registration Statement No. 333-45206
4.23     X                     X       and incorporated by reference herein)

                                       Indenture dated as of January 1, 1996
                                       between PSNC and First Union National
4.24     X                     X       (Filed as Exhibit 4.08 to Registration
                                       Statement No.333-45206 and incorporated
                                       by reference herein)

                                       First Supplemental Indenture dated as of
 4.25     X                     X      January 1, 1996, between PSNC and Bank of
                                       North Carolina, as Trustee (Filed
                                       as Exhibit 4.08 to Registration Statement
                                       (Filed as Exhibit 4.09 to Registration
                                       Statement No. 333-45206 and incorporated
                                       by reference herein)




<PAGE>




                                  EXHIBIT INDEX

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


                                         Second Supplemental  Indenture dated as
                                         of December  15, 1996  between PSNC and
                                         First  Union  National  Bank  of  North
                                         Carolina,  as Trustee (Filed as Exhibit
                                         4.10 to Registration Statement No.
4.26      X                      X       333-45206 and incorporated by reference
                                         herein)

                                         Third  Supplemental  Indenture dated as
                                         of February  10, 2000  between PSNC and
                                         First  Union  National  Bank  of  North
                                         Carolina,  as Trustee (Filed as Exhibit
                                         4.11 to
4.27      X                      X       Registration Statement No. 333-45206
                                         and incorporated by reference herein)

                                         Fourth Supplemental  Indenture dated as
                                         of February  12, 2001  between PSNC and
                                         First Union National Bank of North
4.28      X                      X       Carolina, as Trustee (Filed herewith)

4.29                             X       PSNC $150 million medium-term note
                                         issued February 16, 2001 (Filed
                                         herewith)

                                         SCANA Voluntary Deferral Plan as
                                         amended through October 21, 1997 (File
                                         as Exhibit 10.01 to Registration
10.01     X                              Statement No. 333-49960 and
                                         incorporated by reference herein)

                                         SCANA      Supplementary      Executive
                                         Retirement Plan as amended and restated
                                         effective as of October 21, 1997 (Filed
                                         as  Exhibit  10.01(b)  to  Registration
                                         Statement No.333-86803 and incorporated
10.02     X                              by reference herein)

                                         SCANA Supplementary  Voluntary Deferral
                                         Plan as amended  and  restated  through
                                         October  21,  1997  (Filed  as  Exhibit
                                         10.02  to  Registration  Statement  No.
                                         333-49960 and
10.03     X                              incorporated by reference herein)

                                         SCANA Key Executive Severance Benefits
                                         Plan as amended and restated effective
                                         as of October 21, 1997 (Filed as
                                         Exhibit 10.01(c) to Registration
                                         Statement No. 333-86803
10.04     X                              and incorporated by reference herein)

                                         SCANA Supplementary Key Executive
                                         Severance Benefits Plan effective as of
                                         December 17, 1997 (Filed as Exhibit
                                         10.01(d) to Registration Statement No.
                                         333-86803  and incorporated by
10.05     X                              reference herein)

                                         SCANA Performance Share Plan as amended
                                         and restated  effective January 1, 1998
                                         (Filed   as    Exhibit    10   (e)   to
                                         Registration  Statement  No.  333-86803
                                         and incorporated by
10.06     X                              reference herein)

                                         SCANA Long-Term Equity Compensation
                                         Plan dated January 2000 filed as
                                         Exhibit 4.04 to Registration Statement
10.07     X                              No. 333-37398 and incorporated by
                                         reference herein)

                                         SCANA Key  Employee  Retention  Plan as
                                         amended and  restated  effective  as of
                                         October  21,  1997  (Filed  as  Exhibit
                                         10.02  to  Registration  Statement  No.
                                         333-49960 and
10.08     X                              incorporated by reference herein)

                                         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
10.09     X                              incorporated by reference herein)




<PAGE>



                                  EXHIBIT INDEX

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


10.10       X                           Description  of  SCANA  Corporation
                                        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)

                                        SCANA Corporation Director Compensation
                                        and Deferral Plan effective January 1,
                                        2001(Filed as Exhibit 10.05 to Registra
                                        tion Statement No. 333-49960 and
                                        incorporated by
10.11       X                           reference herein)

                                        Operating Agreement of Pine Needle LNG
                                        Company, LLC dated August 8, 1995 (Filed
                                        as Exhibit 10.01 to Registration
                                        Statement No. 333-45206 and incorporate
10.12                            X      by reference herein)


                                        Amendment to Operating Agreement of Pin
                                        Needle LNG Company, LLC dated October 1,
                                        1995 (Filed as Exhibit 10.02 to
                                        Registration Statement No. 333-45206 and
10.13                            X      incorporated by reference herein)

                                        Amended Operating Agreement of Cardinal
                                        Extension Company, LLC dated December
                                        19, 1996 (Filed as Exhibit 10.03 to
                                        Registration Statement No. 333-45206 and
10.14                            X      incorporated by reference herein)

                                        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
10.15                            X      reference herein)

                                        Form of Severance Agreement between PSNC
                                        and its  Executive  Officers  (Filed  as
                                        Exhibit 10.05 to Registration  Statement
                                        No.333-45206    and    incorporated   by
                                        reference
10.16                            X      herein)

                                        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
10.17                            X      reference herein)

12.01       X          X         X      Statement Re Computation of Ratios

23.01       X                           Consents of Experts and Counsel
                                        (Independent Auditors' Consent)
24.01       X          X         X      Power of Attorney (Filed herewith)