SCANA CORP, 10-K, 1994-03-09

SCANA CORP
10-K, 1994-03-09
ELECTRIC & OTHER SERVICES COMBINED

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]

For the fiscal year ended December 31, 1993

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the transition period from to

Commission File Number 1-8809

SCANA CORPORATION
(Exact name of registrant as specified in its charter)

SOUTH CAROLINA 57-0784499
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)

1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201
(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code (803) 748-3000

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

Title of each class Name of each exchange on which registered

Common Stock, without par value New York Stock Exchange

Securities registered pursuant to 12(g) of the Act:

None
(Title of class)

Indicate by check mark whether the registrant: (1) has 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
registrant was required to file such reports), and (2) has 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. [ ]

State the aggregate market value of the voting stock held by non-affiliates
of the registrant. The aggregate market value shall be computed by reference
to the price at which the stock was sold, or the average bid and
asked prices of such stock, as of a specified date within 60 days prior
to the date of filing. (See definition of affiliate in Rule 405.)

<PAGE>

Note: If a determination as to whether a particular
person or entity is an affiliate cannot be made without involving
unreasonable effort and expense, the aggregate market value of
the common stock held by non-affiliates may be calculated on the
basis of assumptions reasonable under the circumstances, provided
that the assumptions are set forth in this form.

The aggregate market value of the voting stock held by
nonaffiliates of the registrant was $2,150,844,925 at February
28, 1994 based on the closing price of the Common Stock on such
date, as reported by the New York Stock Exchange composite tape
in The Wall Street Journal.

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all
documents and reports required to be filed by Section 12, 13 or
15(d) of the Securities Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.

Yes No

(APPLICABLE ONLY TO CORPORATE REGISTRANTS)

Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date.

The total number of shares of the registrant's
Common Stock, no par value, outstanding at February 28, 1994
was 46,884,903.

DOCUMENTS INCORPORATED BY REFERENCE.

List hereunder the following documents if incorporated by
reference and the Part of the Form 10-K (e.g., Part I, Part II,
etc.) into which the document is incorporated: (1) any annual
report to security-holders; (2) any proxy or information
statement; and (3) any prospectus filed pursuant to Rule 424(b)
or (c) under the Securities Act of 1933. The listed documents
should be clearly described for identification purposes (e.g.,
annual report to security-holders for fiscal year ended December
24, 1980).

(1) Specified sections of the Registrant's 1994 Proxy Statement,
dated March 22, 1994, in connection with its 1994 Annual
Meeting of Stockholders, are incorporated by reference in
Part III hereof.

<PAGE>

TABLE OF CONTENTS

Page

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

PART I

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

Item 2. Properties .......................................... 20

Item 3. Legal Proceedings ................................... 23

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

Corporate Structure........................................... 24

Executive Officers of the Registrant.......................... 25

PART II

Item 5. Market for Registrant's Common Stock
and Related Security Holder Matters ................ 26

Item 6. Selected Financial Data ............................. 27

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations....... 29

Item 8. Financial Statements and Supplementary Data ......... 38

Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ............. 72

PART III

Item 10. Directors and Executive Officers of the
Registrant ......................................... 72

Item 11. Executive Compensation .............................. 72

Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 72

Item 13. Certain Relationships and Related Transactions ...... 72

PART IV

Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 73

SIGNATURES......................................................... 74

<PAGE>

DEFINITIONS

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

ABBREVIATION TERM

AFC......................... Allowance for Funds Used During Construction
BTU......................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act............... Clean Air Act Amendments of 1990
Company..................... SCANA Corporation and its subsidiaries
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... 1 million BTUs
Development Corporation..... SCANA Development Corporation
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
DRP......................... SCANA Corporation Dividend Reinvestment and Stock
Purchase Plan
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.
Hydrocarbons.................SCANA Hydrocarbons, Inc.
KVA......................... Kilovolt-ampere
KW.......................... Kilowatt
KWH......................... Kilowatt-hour
LNG......................... Liquefied Natural Gas
MCF......................... Thousand Cubic Feet
MW.......................... Megawatt
NEPA........................ National Energy Policy Act of 1992
NRC......................... United States Nuclear Regulatory Commission
Peoples..................... Peoples Natural Gas Company of South Carolina
Petroleum Resources......... SCANA Petroleum Resources, Inc.
Pipeline Corporation........ South Carolina Pipeline Corporation
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935
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
Suburban.................... Suburban Propane Group, Inc.
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipe Line Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams coal-fired, electric generating
station owned by GENCO

<PAGE>
PART I

ITEM 1. BUSINESS

THE COMPANY

ORGANIZATION

SCANA, a South Carolina corporation having general
business powers, was incorporated on October 10, 1984 and is
a public utility holding company within the meaning of PUHCA but
is presently exempt from registration under such Act (see
Regulation). SCANA has its principal executive office at 1426
Main Street, Columbia, South Carolina 29201, telephone number
(803) 748-3000. SCANA holds all the capital stock of each of its
subsidiaries except for the Preferred Stock of SCE&G and the
capital stock of SCANA's indirect, wholly owned subsidiaries
which are not material individually or in the aggregate. SCANA
and its subsidiaries had 4,788 full-time, permanent employees as
of December 31, 1993 as compared to 4,849 full-time, permanent
employees as of December 31, 1992.

SEGMENTS OF BUSINESS

SCANA neither owns nor operates any physical properties. It
currently has 11 direct, wholly owned subsidiaries which are
engaged in the functionally distinct operations described below.

Regulated Utilities

The Company's principal subsidiary, 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 areas of
Columbia and Charleston, 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 its use
for 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 29 of the 46 counties
in South Carolina and covers more than 19,000 square miles.
Total estimated population of counties representing the combined
service area is approximately 2.3 million.

The predominant industries in the territories served by
SCE&G include: synthetic fibers; chemicals and allied products;
fiberglass and fiberglass products; paper and wood products;
metal fabrication; stone, clay and sand mining and processing;
and various textile-related products.

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 and fossil fuel
requirements.

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 39
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.

<PAGE>

Nonregulated Businesses

Petroleum Resources owns and operates oil and gas producing
properties with net proven reserves in 16 states and Federal
waters offshore Texas and Louisiana.

Hydrocarbons markets natural gas and light hydrocarbons. It
also owns and operates an 80 million gallon underground propane
storage cavern near York, South Carolina and a 62 mile, six-inch
propane pipeline that connects the cavern facility with Dixie
Pipeline Company near Bethune, South Carolina. The cavern leases
storage space to industries, utilities and propane suppliers.
Hydrocarbons also owns and operates the Wilburton Gathering
System in Oklahoma.

Suburban purchases, delivers and sells propane. In 1993
Suburban sold approximately 20 million gallons of propane and had
approximately 31,400 residential, commercial and industrial
customers at year end.

MPX Systems, Inc. is involved in telecommunication related
ventures providing fiber optic telecommunications, video
conferencing and specialized mobile radio services. Having
installed over 600 miles of fiber optic cable in South Carolina,
Georgia and Alabama, the company has recently turned its efforts
toward video conferencing and the establishment of a Specialized
Mobile Radio system in South Carolina. Both new ventures
capitalize on the fiber infrastructure in place and provide for
expansion of the network.

Development Corporation is engaged in the development,
management and sale of real estate. In January 1994 SCANA signed
an agreement to sell in 1994 substantially all of the real estate
assets of Development Corporation to Liberty Properties Group,
Inc. of Greenville, South Carolina for $91.5 million. On March
4, 1994 the Company and Liberty amended the agreement regarding
the sale. Under the terms of the amended agreement certain
projects currently under construction will be excluded from the
transaction and the sales price will be $49.6 million. All of
the sales price will be received at the time of closing. The
transaction will not have a material impact on the Company's
financial position or results of operation.

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

SCANA Capital Resources, Inc. has provided equity capital
for diversified investments.

Information with respect to major segments of business for
the years ended December 31, 1993, 1992 and 1991 is contained in
Note 11 of the Notes to Consolidated Financial Statements and all
such information is incorporated herein by reference.

CAPITAL REQUIREMENTS AND FINANCING PROGRAM

Capital Requirements

The cash requirements of the Company arise primarily from
SCE&G's operational needs, the Company's construction program and
the need to fund the activities or investments of the Company's
nonregulated subsidiaries. The ability of the Company'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. The Company'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 expand their
construction programs, it is 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 relief.

As discussed in Note 2A of Notes to Consolidated Financial
Statements, on June 7, 1993 the PSC issued an order granting
SCE&G a 7.4% annual increase in retail electric rates to be
implemented in two phases of $42.0 million annually effective
June 1993 and $18.5 million annually effective June 1994, based
on a test year.

<PAGE>

During 1994 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 38% excluding dividends), sales of additional
shares of common stock including sales pursuant to the DRP and
SPSP, and the issuance and sale of debt securities. Short-term
liquidity is expected to be provided by issuance of commercial
paper. The timing and amount of such sales and the type of
securities to be sold will depend upon market conditions and
other factors.

The Company's estimates of its cash requirements for
construction (excluding potential oil and gas investments) and
nuclear fuel expenditures, which are subject to continuing review
and adjustment, for 1994 and the four-year period 1995-1998 as
now scheduled are as follows:

Type of Facilities 1994 1995-1998
(Thousands of Dollars)
South Carolina Electric & Gas Company:
Electric Plant:
Generation . . . . . . . . . . . . . . $245,037 $ 539,180
Transmission . . . . . . . . . . . . . 21,230 94,177
Distribution . . . . . . . . . . . . . 58,178 295,523
Other. . . . . . . . . . . . . . . . . 12,815 42,975
Nuclear Fuel. . . . . . . . . . . . . . . 28,064 84,770
Gas . . . . . . . . . . . . . . . . . . . 15,814 62,276
Transit . . . . . . . . . . . . . . . . . 422 749
Common . . . . . . . . . . . . . . . . . 30,650 54,715
Nonutility . . . . . . . . . . . . . . . 139 545
Total . . . . . . . . . . . . . . . . . 412,349 1,174,910
Other Companies Combined. . . . . . . . . . 121,725 416,523
Total . . . . . . . . . . . $534,074 $1,591,433

The above estimates exclude AFC.

</TABLE>

Construction

The Company's cost estimates for its construction program
for the periods 1994 and 1995-1998 shown in the above table
include costs of the projects described below.

SCE&G entered into a contract with Duke/Fluor Daniel in 1991
to design, engineer and build a 385 MW coal-fired electric
generating plant near Cope, South Carolina in Orangeburg County.
Construction of the plant began in November 1992 with commercial
operation expected in late 1995 or early 1996. The estimated
price of the Cope plant, excluding financing costs and AFC but
including an allowance for escalation, is $450 million. In
addition, the transmission lines for interconnection with SCE&G's
system are expected to cost $26 million.

The steam generators at Summer Station will be replaced
during the 1994 regularly scheduled refueling outage. In January
1994 SCE&G, acting on behalf of itself and the PSA (as co-owners
of the 885 Megawatt Summer Station), reached a settlement with
Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provide by Westinghouse to
Summer Station which are defective in design, workmanship and
materials. Terms of the settlement are confidential by
agreement of the parties and order of the court. SCE&G had filed
an action in May 1990 against Westinghouse in the U. S. District
Court for South Carolina; an order dismissing this suit was
issued on January 12, 1994.

Pipeline Corporation completed construction in 1993 of an
LNG facility near Sally, South Carolina at a price of $23.5
million. The facility will store up to 900,000 MCF of LNG.

During 1993 SCE&G and GENCO expended approximately $24
million as part of a program to extend the operating lives of
certain generating facilities. Additional improvements to be
made under the program during 1994 are estimated to cost
approximately $22 million.

<PAGE>

Additional Capital Requirements

In addition to the Company's capital requirements for 1994
described above, $25.6 million will be required for refunding and
retiring outstanding securities and obligations. For the years
1995-1998, the Company has an aggregate of $255.8 million of
long-term debt maturing (including approximately $43.9 million
for sinking fund requirements, of which $43.5 million may be
satisfied by deposit and cancellation of bonds issued upon the
basis of property additions or bond retirement credits) and $9.9
million of purchase or sinking fund requirements for preferred
stock.

Actual 1994 expenditures may vary from the estimates set
forth above due to factors such as inflation, economic
conditions, regulation, legislation, rates of load growth,
environmental protection standards and the cost and availability
of capital.

Financing Program

The Company has in effect a medium-term note program for the
issuance from time to time of unsecured medium-term debt
securities. The proceeds from the sales of these securities may
be used to fund additional business activities in nonutility
subsidiaries, to reduce short-term debt incurred in connection
therewith or for general corporate purposes. In 1993 the Company
issued $60 million of such medium-term notes. The proceeds from
the sales of these securities were used for the funding of
nonutility subsidiary activities. At December 31, 1993 the
Company had available for issuance $67.6 million under this
program.

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 15 months prior to the month of issuance is at least twice
the annual interest requirements on all Class A Bonds to
be outstanding (Bond Ratio). For the year ended December 31,
1993 the Bond Ratio was 3.70. The issuance of additional Class A
Bonds is restricted also to an additional principal amount equal
to 60% of unfunded net property additions (which unfunded
property additions totaled approximately $219.9 million at
December 31, 1993), Class A Bonds issued on the basis of
retirements of Class A Bonds (which retirement credits totaled
$10.9 million at December 31, 1993) and Class A Bonds issued on
the basis of cash on deposit with the Trustee.

SCE&G has placed a new bond indenture (New Mortgage) dated
April 1, 1993 on substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are expected to be 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 $157 million
were available for such purpose at December 31, 1993), until such
time as all presently outstanding Class A Bonds are retired.
Thereafter, New Bonds will be issuable on the basis of property
additions in a principal amount equal to 70% of the original cost
of electric and common plant properties (compared to 60% of value
for Class A Bonds under the Old Mortgage), cash deposited with
the Trustee, and retirement of New Bonds. New Bonds will be
issuable under the New Mortgage only if adjusted net earnings (as
therein defined) for 12 consecutive months out of the 18 months
immediately preceding the month of issuance are at least twice
the annual interest requirements on all outstanding bonds
(including Class A Bonds) and New Bonds to be outstanding (New
Bond Ratio). For the year ended December 31, 1993 the New Bond
Ratio was 5.0.

On April 29, 1993 the Securities and Exchange Commission
(SEC) declared effective a registration statement for the
issuance of up to $700 million of New Bonds by SCE&G. The
following series, aggregating $600 million, have been issued
under such registration statement:

On June 9, 1993, $100 million, 7 5/8% Series due June 1, 2023
to repay short-term borrowings in a like amount.

On July 1, 1993, $100 million, 6% Series due June 15,
2000, and $150 million, 7 1/8% Series due June 15, 2013, and
on July 20, 1993, $150 million, 7 1/2% Series due June 15,
2023, to redeem, on July 20, 1993, $382,035,000 of First and
Refunding Mortgage Bonds maturing between 1999 and 2017 and
bearing interest at rates between 8% and 9 7/8% per annum.

<PAGE>

On December 20, 1993, $100 million, 6 1/4% Series due December
15, 2003 to repay short-term borrowings in a like amount.

The following additional financing transactions have occurred
since December 31, 1992:

On January 15, 1993 the Company closed on an unsecured bank
loan in the principal amount of $60 million, due January 14,
1994, and used the proceeds to pay off a loan in a like
amount. The interest rate is the three month LIBOR plus 30
basis points and is reset quarterly. On January 14, 1994 the
Company refinanced the loan with unsecured bank loans totaling
$60 million, due January 13, 1995 at interest rates between
3.875% and 3.89%.

On April 15, 1993 the Company arranged for a $15 million term
loan, due April 14, 1994, to repay short-term borrowings in a
like amount. The interest rate is the three month LIBOR plus
16 basis points and is reset quarterly.

On June 1, 1993 SCE&G redeemed the following amounts of First
and Refunding Mortgage Bonds: $35 million, 10 1/8% Series due
2009 and $13 million, 9 7/8% Series due 2009.

On June 2, 1993 the Company entered into a $123 million 90-day
bank loan (90-day bank loan) to finance the acquisition by
Petroleum Resources of approximately 125 billion cubic feet
equivalent of natural gas reserves through the purchase of
NICOR Exploration and Production Co.

On July 1, 1993 the Company issued $60 million of medium-term
notes bearing interest at the following rates and maturing on
the following dates in the following amounts: $20 million,
5.76%, due July 1, 1998; $20 million, 6.15%, due July 3, 2000;
$20 million, 6.51%, due July 1, 2003. The proceeds were used
to repay a portion of the 90-day bank loan discussed above.

In early August 1993 the Company issued 1,467,000 shares of
common stock with net proceeds totalling $69,345,090. The
proceeds were used to repay the remainder of the 90-day bank
loan discussed above and for general corporate purposes.

On September 30, 1993 Pipeline Corporation sold unsecured
promissory notes totalling $25 million, 6.72% due September
30, 2013. The proceeds were used to repay short-term
borrowings in a like amount.

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 10% of the aggregate principal amount
of all of SCE&G's secured indebtedness and capital and surplus;
provided, however, that no such consent shall be 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 in-
debtedness. The FERC has authorized SCE&G to issue up to $200
million of unsecured promissory notes or commercial paper
with maturity dates of 12 months or less but not later than
December 31, 1995. GENCO has not sought such authorization.

The Company had $175.0 million authorized lines of credit
and had unused lines of credit of $148.0 million at December 31,
1993.

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 is 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,
1993 the Preferred Stock Ratio was 2.52.

<PAGE>

On October 12, 1993 the Company registered with the SEC
2,000,000 additional shares of the Company's common stock to be
issued and sold under the DRP.

During 1993 the Company issued 529,954 shares of the
Company's common stock under the DRP. In addition, the Company
issued 705,498 shares of its common stock pursuant to its SPSP.
The Company has authorized and reserved for issuance, and
registered under effective registration statements, 2,065,824 and
872,420 shares of common stock pursuant to the DRP and the SPSP,
respectively.

In January 1994 SCANA signed an agreement to sell in 1994
substantially all of the real estate assets of Development
Corporation to Liberty Properties Group, Inc. of Greenville,
South Carolina for $91.5 million. On March 4, 1994 the Company
and Liberty amended the agreement regarding the sale. Under the
terms of the amended agreement certain projects currently under
construction will be excluded from the transaction and the sales
price will be $49.6 million. All of the sales price will be
received at the time of closing. The net proceeds from the sale
will be used to retire Development Corporation's debt and for
general corporate purposes, including the funding of other
nonutility subsidiaries' business activities. The transaction
will not have a material impact on the Company's financial
position or results of operations.

The ratio of earnings to fixed charges (SEC method) was
3.41, 2.79, 3.24, 4.07 and 2.93 for the years ended December 31,
1993, 1992, 1991, 1990 and 1989 respectively.

The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements.

Fuel Financing Agreements

SCE&G has assigned to Fuel Company all of its rights and
interests in its various contracts relating to the acquisition
and ownership of nuclear and fossil fuel. To finance nuclear and
fossil fuel inventories, Fuel Company issues, from time to time,
its promissory notes with maturities of less than 270 days
(Commercial Paper). The issuance of Commercial Paper is
supported by an irrevocable revolving credit agreement which
expires July 31, 1996 and is guaranteed by SCE&G. Accordingly,
the amounts outstanding have been included in long-term debt.
The credit agreement provides for a maximum amount of $75 million
that may be outstanding at any time.

At December 31, 1993 Commercial Paper outstanding for
nuclear and fossil fuel inventories was approximately $36.8
million at a weighted average interest rate of 3.47%.

ELECTRIC OPERATIONS

Electric Sales

In 1993 residential sales of electricity accounted for 43%
of electric sales revenues; commercial sales 29%; industrial
sales 21%; sales for resale 4%; and all other 3%. KWH sales by
classification for the years ended December 31, 1993 and 1992 are
presented below:

Sales
KWH %
Classification 1993 1992 Change
(thousands)

Residential 5,650,753 5,155,886 9.60
Commercial 4,835,492 4,531,683 6.70
Industrial 4,887,121 4,684,012 4.34
Sale for resale 1,005,968 946,357 6.30
Other 500,937 476,064 5.22
Total Territorial 16,880,271 15,794,002 6.88
Interchange 198,059 77,046 157.07
Total 17,078,330 15,871,048 7.61

<PAGE>

SCE&G furnishes electricity for resale to three
municipalities, three investor-owned utilities, two electric
cooperatives and one public power authority. Such sales for
resale accounted for 4% of SCE&G's total electric sales revenues
in 1993.

An increase of 6,974 electric customers to 468,874 total
customers contributed to in an all-time peak demand record of
3,557 MW on July 29, 1993. The previous years' record of 3,380
MW was set July 13, 1992.

Electric Interconnections

SCE&G's transmission system is part of the interconnected
grid extending over a large part of the southern and eastern
portion of the nation. SCE&G, Virginia Power Company, Duke Power
Company, Carolina Power & Light Company, Yadkin, Incorporated and
PSA are members of the Virginia-Carolinas Reliability Group, one
of the several geographic divisions within the Southeastern
Electric Reliability Council which 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 Southeastern Power Administration's Clark Hill
Project.

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
1991-1993.

1991 1992 1993
Nuclear:
Per million BTU $ .57 $ .52 $ .47
Coal:
Per ton $41.78 $40.45 $40.48
Per million BTU 1.63 1.57 1.57
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.38 $ 1.27 $ 1.33

The fuel costs shown above exclude the effects of a PSC
approved offsetting of fuel costs through the application of
credits carried on SCE&G's books as a result of a 1980 settlement
of certain litigation.

Fuel Supply

The following table shows the sources and approximate
percentages of total KWH generation by each category of fuel for
the years 1991-1993 and the estimates for 1994 and 1995.

Percent of Total KWH Generated
Actual Estimated
1991 1992 1993 1994 1995

Coal 68% 65% 72% 77% 69%
Nuclear 21 29 22 17 26
Hydro 5 5 5 5 5
Natural Gas & Oil 6 1 1 1 -
100% 100% 100% 100% 100%

Coal is currently used at all four of SCE&G's major fossil
fuel-fired plants and GENCO's Williams Station. Unit train
deliveries are used at all of these plants. On December 31,
1993 SCE&G had approximately a 73-day supply of coal in inventory
and GENCO had approximately a 56-day supply.

<PAGE>

The supply of 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
the Company's existing contracts. Contracts for the purchase of
coal represent the following percentages of estimated
requirements for 1994 (approximately 5.3 million tons) and expire
at the dates indicated (giving effect to the Company's potential
to exercise renewal options):

Range of % of Final
No. of Tons % of 1994 Sulfur Content Expiration Renegotiation
Per Year Requirement per Contract Date (1) Date (1)

966,664 18.2 up to 1.55 02/28/2001 02/28/1995
360,000 6.8 1.00-1.80 12/31/2002 12/31/1996
134,000 2.5 1.10-2.00 03/31/1996 03/31/1994
120,000 2.3 1.10-1.60 04/30/1996 04/30/1994
972,000 18.3 up to 1.50 12/31/2002 12/31/1996
192,832 3.6 0.80-1.50 06/30/2000 06/30/1994
2,745,496 51.7

(1) Contract extensions beyond the stated renegotiation date to
the final expiration date are subject to mutual agreement on
price, terms, quantity and quality.

All of the above contracts, except the contracts expiring in
March 1994 and April 1994 which have firm prices, are subject to
periodic price adjustments based on changes in indices published
by the U. S. Department of Labor.

Coal purchased in December 1993 had an average sulfur
content of 1.17%, which permitted SCE&G and GENCO to comply with
existing environmental regulations. The Company believes that
SCE&G's and GENCO's operations are in substantial compliance with
all existing regulations relating to the discharge of sulfur
dioxide. The Company has not been advised by officials of DHEC
that any more stringent sulfur content requirements for existing
plants are contemplated. However, the Company will be required
to meet the more stringent emissions standards established by the
Clean Air Act (see "Environmental Control Matters").

SCE&G currently has adequate supplies of uranium under
contract to manufacture nuclear fuel for Summer Station through
1996. The following table summarizes all contract commitments for
the stages of nuclear fuel assemblies:

Commitment Contractor Regions(1) Term

Uranium NUEXCO Trading
Corporation 11 1994
Uranium Energy Resources
of Australia 9-13 1990-1996
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995
Enrichment DOE (2) Through 2022
Fabrication Westinghouse 1-21 1982-2009
Reprocessing None

(1) A region represents approximately one-third to one-half of
the nuclear core in the reactor at any one time. Region no.
10 was loaded in 1993 and region no. 11 will be loaded in
1994.

(2) The contract with the DOE is a "requirements" type contract
whereby the DOE supplies total enrichment requirements for
the unit through the year 2022, as specified by its then
current schedule.

SCE&G has on-site spent fuel storage capability until at
least 2008 and expects to be able to expand its storage capacity
to accommodate the spent fuel output for the life of the plant
through rod consolidation, 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 Control
Matters" for information regarding the contract with the DOE for
disposal of spent fuel.)

<PAGE>

GAS OPERATIONS

Gas Sales

In 1993 residential sales accounted for 13% of gas sales
revenues; commercial sales 9%; industrial sales 30%; sales for
resale 19% and transportation gas 29%. Dekatherm sales by
classification for the years ended December 31, 1993 and 1992 are
presented below:

SALES
DEKATHERMS %
CLASSIFICATION 1993 1992 CHANGE

Residential 12,651,000 11,847,723 6.8
Commercial 9,611,556 9,729,723 (1.2)
Industrial 30,335,059 33,157,246 (8.5)
Sale for resale 19,144,130 21,437,448 (10.7)
Transportation gas 29,542,805 25,720,633 14.9
Total 101,284,550 101,892,773 (0.6)

During 1993 the Company added 3,853 customers, increasing its
total customers to 234,736.

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

The deregulation of natural gas prices at the wellhead which
took place on January 1, 1985, and the changes in the prices of
natural gas that have occurred under Federal regulation have
resulted in the development of a spot market for natural gas in
the producing areas of the country. Pipeline Corporation has
been successful in purchasing lower cost natural gas in the spot
market and arranging for its transportation to South Carolina.
Pipeline Corporation has also negotiated contracts with certain
direct and indirect industrial customers for the transportation
of natural gas that the industrial customers purchase directly
from suppliers.

On April 8, 1992, the FERC promulgated its Order No. 636,
which is 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 supplies whether
the customer purchases gas from the pipeline or another supplier.
Both of Pipeline Corporation's interstate suppliers initiated
transportation services in compliance with FERC Order No. 636 on
November 1, 1993. The Company's gas subsidiaries are positioned
for the related market changes arising from this order. Pipeline
Corporation, operating wholly within the State of South Carolina,
provides natural gas utility service, including transportation
services, for its customers, and supplies natural gas to SCE&G
and other wholesale purchasers. Hydrocarbons acquires and sells
natural gas in the newly deregulated markets. Petroleum
Resources owns natural gas reserves that supply natural gas for
the interstate markets. Neither Hydrocarbons nor Petroleum
Resources supply natural gas to any affiliate for use in
providing regulated gas utility services.

To reduce dependence on imported oil, NEPA imposes purchase
requirements for alternate fuel vehicles for federal, state,
municipal and private fleets which increase over a period of
years. The Company expects these requirements for alternate fuel
vehicles to develop business opportunities for the sale of
compressed natural gas as fuel for vehicles, but it cannot
predict the extent of this new market.

Expansion

SCANA and Sonat, Inc., parent company of Southern Natural,
are evaluating the potential market to determine the feasibility
of providing natural gas transportation service to North
Carolina.

<PAGE>

Gas Cost and Supply

Pipeline Corporation purchases natural gas under contracts
with producers, brokers and interstate pipelines. The gas is
brought to South Carolina through contracts with both Southern
Natural and Transco. The volume of gas which Pipeline
Corporation is entitled to transport through these contracts is
shown below:

Maximum Daily
Supplier Contract Demand Capacity (MCF)

Southern Natural Firm Transportation 160,000
Transco Firm Transportation 29,900
Total 189,900

A liquid natural gas storage facility was completed in 1993
and has been used and useful in providing supplemental supplies
to meet firm system requirements this winter season. No
difficulty in obtaining natural gas is anticipated.

During 1993 the average cost per MCF of natural gas
purchased for resale, including spot market purchases, was
approximately $2.68 compared to approximately $2.51 during 1992.

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 storage tanks are capable of storing the liquefied equivalent
of 1,900,000 MCF of natural gas, of which approximately 1,450,000
MCF were in storage at December 31, 1993. On peak days the LNG
plants can regasify up to 150,000 MCF per day. Additionally,
Pipeline Corporation had contracted for 6,398,035 MCF of natural
gas storage space on December 31, 1993, of which 4,880,484 MCF
were in storage at such date. Propane air peak shaving
facilities located in the Company's service area can supply an
additional 137,400 MCF per day.

The Company believes that current supplies under contract
and spot market purchases of natural gas are adequate to meet
existing customer demands for service and to accommodate growth.

Curtailment Plans

The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline
companies to their customers which require Southern Natural and
Transco to allocate capacity to Pipeline Corporation.

The FERC allocation priorities are not applicable to
deliveries by Pipeline Corporation to its customers, which are
governed by a separate curtailment plan approved by the PSC.

Gas Reserves

Petroleum Resources is actively involved in oil and natural
gas development and production activities. It currently own and
operates oil and gas production properties with net proven
reserves in Texas, Louisiana, Mississippi, Oklahoma, California,
Arkansas, Nebraska, Colorado, Kansas, Montana, North Dakota,
Michigan, Illinois, New Mexico, Alabama, Wyoming and Federal
waters offshore Texas and Louisiana.

Gas Marketing

Hydrocarbons markets natural gas as well as other light
hydrocarbons.

Propane Operations

Hydrocarbons owns and operates an 80 million gallon under-
ground propane storage facility that leases storage space to
industrial companies, utilities and others. It also owns and
operates a 62 mile propane pipeline connected to the Dixie
Pipeline System which traverses central South Carolina.
Hydrocarbons also owns and operates the Wilburton Gathering
System in Oklahoma.

<PAGE>

REGULATION
General

SCANA is a public utility holding company within the
meaning of PUHCA, but is exempt under Section 3(a)(1) of PUHCA,
from regulation by the SEC as a registered holding company,
unless and until the SEC shall otherwise order, except for
Section 9(a)(2) thereof prohibiting the acquisition of securities
of other public utilities without a prior order of the SEC.

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.

National Energy Policy Act of 1992

Congress has passed NEPA, the principal thrust of which is
to create a more competitive wholesale power supply market by
creating "exempt wholesale generators" (EWGs) designated by the
FERC, which are independent power producers (IPPs) whose owners
will not become holding companies under PUHCA. Upon application
of a wholesaler of electric energy, the FERC may order any
electric utility that owns transmission facilities used for
wholesale sales of electric energy to provide transmission
service (including any enlargement of transmission capacity
needed to provide the service) to the applicant. Charges for
transmission service must be "just and reasonable" and a utility
is entitled to recover "all legitimate, verifiable economic
costs" incurred in connection with any transmission service so
ordered. The FERC may not order such service where it (1) would
"unreasonably impair the continued reliability of electric
wheeling" judged by reference to "consistently applied regional
or national reliability standards, guidelines or criteria;" (2)
would result in "retail wheeling;" or (3) would conflict with
state laws governing retail marketing areas of electric
utilities. Electric utilities, including exempt and non-exempt
holding companies, may own and operate EWGs subject to advance
approval by state utility commissions, which are given access to
books and records of the EWG and its affiliates to the extent
that such a commission requires access to perform its regulatory
duties. It allows both registered and exempt utility holding
companies to acquire interests in foreign utility companies
engaged in the generation, transmission or distribution of
electricity or the retail distribution of gas, where a state
commission has certified that it has the ability to protect the
utility's retail ratepayers against adverse investments in
foreign utilities by affiliates of public utilities that such
commissions regulate. State Commissions must consider rate
making changes and other regulatory reform to ensure that
electric utilities' investments in energy efficiency and demand
side management programs are at least as profitable as investing
in new generating capacity. FERC has issued a Notice of Proposed
Rule Making to develop regulations under NEPA concerning EWGs and
electric transmission service.

NEPA also has provisions concerning nuclear power, alternate
fuel vehicles, minimum efficiency standards, integrated resource
planning, demand side management incentives, a variety of energy
research projects relating to environmental measures, electric
and magnetic fields, hydroelectric projects, and global warming.
It authorizes one step licensing for nuclear power plants and
requires EPA to issue standards for the Yucca Mountain repository
site for nuclear waste (see "Nuclear Fuel Disposal" under
"Environmental Control Matters"). To reduce dependence on
imported oil, NEPA imposes purchase requirements for alternate
fuel vehicles for federal, state, municipal and private fleets
which increase over a period of years (see "Gas Operations").

In the opinion of the Company, it will be able to meet
successfully the challenges of an altered business climate for
electric and gas utilities and natural gas businesses. Neither
the application of NEPA or FERC Order No. 636 to it and its
subsidiaries, nor the development of an EWG industry, new markets
and obligations for transmission services for wholesale sales of
electricity, nor deregulated interstate natural gas markets is
expected to have a material adverse impact on the results of its
operations, its financial position or its business prospects.

Federal Energy Regulatory Commission

SCE&G and GENCO are subject to regulatory jurisdiction under
the Federal Power Act, administered by the FERC and the 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.

<PAGE>

SCE&G holds licenses under the Federal Water Power Act or
the Federal Power Act with respect to all its hydroelectric
projects. The expiration dates of the licenses covering the
projects are as follows: Neal Shoals (5,000 KW capability) and
Stevens Creek (9,000 KW capability) 1993; Columbia (10,000 KW
capability) 2000; Saluda Project (206,000 KW capability) 2007;
and Parr Shoals (14,000 KW capability) and Fairfield Pumped
Storage Project (512,000 KW capability) 2020. Pursuant to the
provisions of the Federal Power Act as amended by the Electric
Consumers Protection Act of 1986, applications for new licenses
for Neal Shoals and Stevens Creek were filed with the FERC on
December 30, 1991. No competing applications were filed. The
Neal Shoals license application was accepted for filing by the
FERC on September 30, 1992 and the Stevens Creek application was
accepted September 15, 1993. FERC has issued Notices of
Authorization for Continued Project Operation for both projects
until FERC has acted on SCE&G's applications for new licenses.
FERC has announced its intentions to perform a Multiple-project
Environmental Assessment for Neal Shoals, and a Multiple-project
Environmental Impact Statement for Stevens Creek.

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

SCE&G is subject to regulation by the NRC with respect to
the ownership and operation 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. The NRC conducts semiannual reviews
that identify plants that have demonstrated an excellent level of
safety performance. Summer Station was recognized in both 1993
reviews as one of the top nuclear plants in the country.

In addition, the Federal Emergency Management Agency is
responsible for the review, in conjunction with the NRC, of
certain aspects of emergency planning relating to the operation
of nuclear plants.

RATE MATTERS

The following table presents a summary of significant rate
activity for the years 1990 - 1993 based on test years:

<TABLE>
<S> <C> <C> <S> <C> <C> <S>
REQUESTED GRANTED

Date of
General Rate Application/ Amount % Increase Date of Amount % of Increase
Applications Hearing (Millions) Requested Order (Millions) Granted

PSC
Electric
Retail 01/03/89 $ 27.2 3.7% 07/03/89 $ 18.2* 67%*
Retail 12/07/92 $ 72.0** 11.4% 06/07/93 $ 60.5 84%

Transit
Fares 03/12/92 $ 1.7 42.0% 09/14/92 $ 1.0 59%

*Reflects a rate reduction of $3.7 million on January 4, 1993 (see discussion below) and excludes impact of
rate reduction of $7.7 million on January 3, 1990 which corresponds to $7.7 million reduction in cost-of-
service resulting from NRC approval of extension of Summer Station's operating life to 40 years.

**As modified.

</TABLE>

<PAGE>

On June 7, 1993 the PSC issued an order on the Company's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually
based on a test year. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, based on a test year.
The Company's request, as modified, had proposed a return on
equity of 12.05% and had projected annual increases of $53.0
million and $19.0 million for phases one and two, respectively.

On September 14, 1992 the PSC issued an order granting SCE&G
a $.25 increase in transit fares from $.50 to $.75 in both
Columbia and Charleston, 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 on October 5, 1992. SCE&G
has appealed the PSC's order to the Circuit Court. During oral
arguments in February 1994 the Circuit Court retained
jurisdiction and remanded the decision to the PSC for the limited
purpose of answering questions concerning the applicable
regulatory principles used by the PSC in determining these
transit rates.

Since November 1, 1991 SCE&G's gas rate schedules for its
residential, small commercial and small industrial customers have
included a weather normalization adjustment (WNA). The WNA
minimizes fluctuations in gas revenues due to abnormal weather
conditions and has been approved through November 1994 subject to
an annual review by the PSC. The PSC order was based on a
return on common equity of 12.25%. The WNA became effective the
first billing cycle in December 1991.

In May 1989 the PSC approved a volumetric and direct billing
method for Pipeline Corporation to recover take-or-pay costs
incurred from its interstate pipeline suppliers pursuant to
FERC-approved final and non-appealable settlements. In December
1992 the Supreme Court approved Pipeline Corporation's full
recovery of the take-or-pay charges imposed by its suppliers and
treatment of these charges as a cost of gas. However, the
Supreme Court declared the PSC-approved "purchase deficiency"
methodology for recovery of these costs to be unlawful
retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. The Company believes that
the elimination of the purchase deficiency method of recovery
will affect the timing for recovery of take-or-pay charges and
shift the allocations among Pipeline Corporation's customers
(including SCE&G) but that all such charges should be ultimately
recovered. The case has been remitted to the PSC by the Supreme
Court and the Company anticipates the PSC will issue an Order
authorizing full recovery of incurred take-or-pay costs on a
prospective volumetric basis after the completion of accounting
verification by the PSC Staff of the principal and associated
interest costs.

On August 8, 1990 the PSC issued an order effective November
1, 1990, approving changes in Pipeline Corporation's gas rate
design for sales for resale service and upholding the "value-of-
service" method of regulation for its direct industrial service.
Direct industrial customers seeking "cost-of-service" based rates
initiated two separate appeals to the Circuit Court, which
reversed and remanded to the PSC its August 8, 1990 order.
Pipeline Corporation appealed that decision to the Supreme Court
which reversed the two Circuit Court decisions and reinstated the
PSC Order. The Supreme Court held that the industrial customer
group's appeal was premature and failed to exhaust administrative
remedies. Additionally, the Supreme Court interpreted the rate-
making statutes of South Carolina to give discretion to the PSC
in selecting the methodology to be used in setting rates for
natural gas service.

On July 3, 1989 the PSC granted SCE&G approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity
of 13.25%. The Consumer Advocate appealed the decision to the
Supreme Court which, on August 31, 1992, found that the evidence
in the record of that case did not support a return on common
equity higher than 13.0% and remanded to the PSC a portion of its
July 1989 order for a determination of the proper return on
common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other non-
material adjustments to the calculation of cost-of-service. The
total refund, before interest and income taxes, was approximately
$14.6 million and was charged against 1992 "Electric Revenues."
The refund plus interest was made during 1993.

On November 28, 1989 the PSC granted SCE&G an increase in
firm retail natural gas rates, effective November 30, 1989,
designed to increase annual revenues by $10.1 million, or 89.5%
out of the requested increase of approximately $11.3 million. In
its order the PSC authorized a 12.75% return on common equity.
The Consumer Advocate appealed to the Supreme Court which on
August 31, 1992 remanded the order to the PSC for redetermination
of the proper amount of litigation expenses to include in the
test period. In January 1993 the PSC reduced the amount of
litigation expense and ordered a refund totaling approximately
$163,000 which was charged against 1992 "Gas Revenues." The
refund was made during 1993.

<PAGE>

Fuel Cost Recovery Procedures

The PSC has established a fuel recovery procedure which
determines the fuel component in SCE&G's retail electric base
rates semiannually based on projected fuel costs for the ensuing
six-month period, adjusted for any overcollection or
undercollection from the preceding six-month period. SCE&G has
the right to request a formal proceeding at any time should
circumstances dictate such a review.

In the April 1993 semiannual review of the fuel cost
component of electric rates, the PSC voted to reduce the rate
from 13.5 mills per KWH to 13.0 mills per KWH, a monthly decrease
of $.50 for an average customer using 1,000 KWH per month. This
reduction coincided with the retail electric rate case effective
June 1993. For the October 1993 review the PSC voted to continue
the rate of 13.0 mills per KWH.

SCE&G's gas rate schedules and contracts include mechanisms
which 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 the October 1993 review the PSC authorized an increase in
the base cost of gas from 41.963 cents per therm to 47.100 cents
per therm which resulted in a monthly increase of $5.14
(including applicable taxes) based on an average of 100 therms
per month on a residential bill during the heating season.
In July 1990 the PSC initiated proceedings for a generic
hearing on the Industrial Sales Program Rider (ISPR) for SCE&G
and Pipeline Corporation. The PSC issued an order dated December
20, 1991 approving a Stipulation and Agreement signed in December
1991 by all parties involved which retained the ISPR with
modifications to Pipeline Corporation's gas cost mechanisms.

ENVIRONMENTAL CONTROL MATTERS
General

Federal and state authorities have imposed environmental
control requirements relating primarily to air emissions,
wastewater discharges and solid, toxic and hazardous waste
management. The Company is attempting to ensure that its
operations meet applicable environmental regulations and
standards. It is difficult to forecast the ultimate effect of
environmental quality regulations upon the existing and proposed
operations. Moreover, developments in these and other areas may
require that equipment and facilities be modified, supplemented
or replaced.

Capital Expenditures

In the years 1991 through 1993, capital expenditures for
environmental control amounted to approximately $83.9 million.
In addition, approximately $9.4 million, $7.9 million, and $6.5
million of environmental control expenditures were made during
1993, 1992 and 1991, respectively, which are included in "Other
operation" and "Maintenance" expenses. It is not possible to
estimate all future costs for environmental purposes but
forecasts for minimum capitalized expenditures are $44.7 million
for 1994 and $320.8 million for the four-year period 1995 through
1998. These expenditures are included in the Company's
construction program.

Air Quality Control

The Federal Clean Air Act of 1970 (the "1970 Act") requires
that electric generating plants comply with primary and secondary
ambient air quality standards with respect to certain air
pollutants including particulates, sulfur oxides and nitrogen
oxides and imposes economic penalties for noncompliance. This
Act was amended with the passage of the Clean Air Act Amendments
of 1990.

<PAGE>

Currently, the Company uses a variety of methods to comply
with the State Implementation Plan (developed pursuant to the
1970 Act), including the use of low sulfur fuel, fuel switching,
reduction of load during periods when compliance cannot be met at
full power, maintenance and improvement of existing electrostatic
precipitators and the installation of new baghouses. SCE&G and
GENCO have been able to purchase sufficient fuel meeting current
sulfur standards for all of their plants. With respect to sulfur
dioxide emissions, none of the Company's electric generating
plants is included among the Phase I plants listed in the Clean
Air Act Amendments of 1990 with a compliance date of January 1,
1995. Both companies will, however, be affected by Phase II
requirements, which have a compliance date of January 1, 2000.
The companies undertook a study in 1992 to determine the most
cost-effective mix of control options to meet the requirements of
the Clean Air Act. Such a control strategy will most likely
result in requiring SCE&G and GENCO to utilize a combination of
the following alternatives to meet its compliance requirements:
(1) burn lower sulfur coal, (2) burn natural gas, (3) retrofit at
least one coal-fired electric generating unit with a scrubber to
remove sulfur dioxide and (4) purchase sulfur dioxide emission
allowances to the extent necessary. In addition, the Company
will install on most of its coal-fired units low nitrogen oxide
burners to reduce nitrogen oxide emissions.

The Company currently estimates that air emissions control
equipment will require capital expenditures of $252 million over
the 1994-1998 period to retrofit existing facilities and an
increased operation and maintenance cost of $31 million per year.
Total capital expenditures required to meet compliance
requirements through the year 2003 are anticipated to be
approximately $275 million.

Water Quality Control

The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater 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. Commensurate with renewal of these permits has been
implementation of a more rigorous control program on behalf of
the permitting agency. The facilities have been developing
compliance plans to meet the additional parameters of control and
compliance has involved updating wastewater treatment
technologies. Amendments to the Clean Water Act proposed
recently in Congress include several provisions which could prove
costly to SCE&G. These include limitations to mixing zones and
the implementation of technology-based standards.

Superfund Act and Environmental Assessment Program

As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore actual expenditures could significantly
differ from the original estimates. Amounts estimated and
accrued to date ($19.6 million) for site assessments and cleanup
relate primarily to regulated operations; such amounts have been
deferred and are being amortized and recovered through rates over
a ten-year period. Estimates to date include, among other
things, the costs estimated to be associated with the matters
discussed in the following paragraphs.
The Company and its principal subsidiary, SCE&G, each own
two decommissioned manufactured gas plant sites which contain
residues of by-product chemicals. The Company and SCE&G have
each maintained an active review of their respective sites to
monitor the nature and extent of the residual contamination.

<PAGE>

an innovative approach to site investigation and cleanup called
"Superfund Accelerated Cleanup Model," allowing the pre-cleanup
site investigations process to be compressed significantly. The
PRPs have negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study (RI/FS) and
a corresponding Scope of Work. Actual field work began November
1, 1993 after final approval and authorization was granted by
EPA. SCE&G is also working with the City of Charleston to
investigate potential contamination from the manufactured gas
plant at the city's aquarium site.

During 1993 SCE&G settled its obligations at the Yellow
Water Road Superfund Site near Jacksonville, Florida, the Spencer
Transformer and Equipment Site in West Virginia and Elliott's
Auto Parts in Benton, Arkansas. No further expenses are
anticipated for these sites.

SCE&G has been listed as a PRP and has recorded liabilities,
which are not considered material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina, the Aqua-Tech
Environmental, Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina.

Solid Waste Control

The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact SCE&G's and GENCO's engineering,
design and operation of existing and future ash management
facilities. Potential cost impacts could be substantial.

Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 (the "1982 Act")
requires that the Federal Government make available by 1998 a
permanent repository for high level radioactive waste and spent
nuclear fuel and imposes a fee of 1.0 mill per KWH of net nuclear
generation after April 7, 1983. Payments, which began in 1983,
are subject to change and will extend through the 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 fuel storage capability until at least
2008 and expects to be able to expand its storage capacity to
accommodate the spent fuel output for the life of the plant
through rod consolidation, dry cask storage or other technology
as it becomes available.

The 1982 Act also imposes on utilities the primary
responsibility for storage of their spent nuclear fuel until the
repository is available. (See "Fuel Supply" under "Electric
Operations" for a discussion of spent fuel storage facilities at
Summer Station.)

OTHER MATTERS

With regard to SCE&G's insurance coverage for Summer
Station, reference is made to Note 10B of Notes to Consolidated
Financial Statements, which is incorporated herein by reference.

ITEM 2. PROPERTIES

The parent company, SCANA Corporation, owns no property
other than the capital stock of each of its subsidiaries. It
owns all of the capital stock of each subsidiary except for the
Preferred Stock of SCE&G and the capital stock of SCANA's
indirect, wholly owned subsidiaries which are not material
individually or in the aggregate. The assets formerly belonging
to Peoples, which were owned by SCANA Corporation, were
transferred to SCE&G on January 1, 1994.

<PAGE>

Reference is made to Schedule V - Property Plant and
Equipment, pages 65 through 70, for information concerning
investments in utility plant and nonutility property. 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."

<PAGE>

ELECTRIC

The following table gives information with respect to electric
generating facilities, all of which are owned by SCE&G except as
noted.

Net Generating
Present Year Capability
Facility Fuel Capability Location In-Service (KW)(1)

Steam
Urquhart Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000
Wateree Coal Eastover, SC 1970 700,000
Williams (2) Coal Goose Creek, SC 1973 560,000
Summer (3) Nuclear Parr, SC 1984 590,000

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
Canadys Gas/Oil Canadys, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 26,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (4) Gas/Oil Parr, SC 1970 60,000
Williams (5) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000

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 512,000

Total 3,864,000

(1) Summer rating.
(2) The steam unit at Williams Station, owned by GENCO, was
converted from oil-fired to coal-fired operation in 1984 and,
with modifications, can be reconverted to oil-fired operation
should the need arise.
(3) Represents SCE&G's two-thirds portion of the Summer Station.
(4) Two of the four Parr gas turbines are leased and have a net
capability of 34,000 KW. This lease expires on June 29, 1996.
(5) The two gas turbines at Williams are leased and have a net
capability of 49,000 KW. This lease expires on June 29, 1997.

<PAGE>

SCE&G owns 424 substations having an aggregate transformer
capacity of 18,624,780 KVA. The transmission system consists of
3,033 miles of lines and the distribution system consists of 15,186
pole miles of lines and 3,006 trench miles of underground lines.

GAS
Natural Gas

SCE&G's gas system, including the system acquired by the
Company from Peoples and transferred to SCE&G on January 1, 1994,
consists of approximately 6,629 miles of three-inch equivalent
distribution pipelines and approximately 10,864 miles of
distribution mains and related service facilities.

Pipeline Corporation's gas system consists of approximately
1,735 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 the other in Salley, South Carolina.
The Charleston facility can liquefy up to 6,000 MCF per day and
store the liquefied equivalent of 1,000,000 MCF of natural gas.
The Salley facility, which became operational in 1994, can store
the liquefied equivalent of 900,000 MCF of natural gas and has no
liquefying capabilities. On peak days, the Charleston facility can
regasify up to 60,000 MCF per day and the Salley facility can
regasify up to 90,000 MCF.

Petroleum Resources owns and operates oil and gas producing
properties with net proven reserves in Texas, Louisiana,
Mississippi, Oklahoma, California, Arkansas, Nebraska, Colorado,
Kansas, Montana, North Dakota, Michigan, Illinois, New Mexico,
Alabama, Wyoming and Federal Waters offshore Texas and Louisiana.

Propane

SCE&G has propane air peak shaving facilities which can
supplement the supply of natural gas by gasifying propane to yield
the equivalent of 102,000 MCF per day of natural gas.

TRANSIT

SCE&G owns 93 motor coaches which operate on a route system of
285 miles.

ITEM 3. LEGAL PROCEEDINGS

For information regarding legal proceedings, see ITEM 1.,
"BUSINESS" and Note 10 of Notes to Consolidated Financial
Statements appearing in Item 8., "FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA."

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

Not Applicable

<PAGE>

CORPORATE STRUCTURE

SCANA CORPORATION
A Holding Company, Owning Eleven
Direct, Wholly Owned Subsidiaries

SOUTH CAROLINA MPX SYSTEMS, INC.
ELECTRIC & GAS COMPANY Provides fiber optic
Generates and sells electricity telecommunications, video
to wholesale and retail customers, conferencing and specialized
purchases, sells and transports mobile radio services.
natural gas at retail and provides
public transit service in Columbia SCANA DEVELOPMENT
and Charleston. CORPORATION
Engages in the acquisition,
SOUTH CAROLINA GENERATING development, management and
COMPANY, INC. sale of real estate.
Owns and operates Williams
Station and sells electricity PRIMESOUTH, INC.
to SCE&G. Engages in power plant
management and maintenance
SOUTH CAROLINA FUEL services.
COMPANY, INC.
Acquires, owns and provides for SCANA HYDROCARBONS, INC.
financing for SCE&G's nuclear and Markets natural gas as well
fossil fuel requirements. as other light hydrocarbons.
Owns and operates a propane
SUBURBAN PROPANE GROUP, INC. pipeline and provides for
Purchases, delivers and transportation and bulk
sells propane. storage of propane.

SCANA CAPITAL RESOURCES, INC. SCANA PETROLEUM RESOURCES, INC.
Has provided equity capital Owns and operates oil and gas
for diversified investments. producing properties.

SOUTH CAROLINA PIPELINE CORPORATION
Purchases, sells and transports natural
gas to wholesale and direct industrial
customers. Owns and operates an LNG plant
for the liquefaction, regasification and
storage of natural gas.

Each of the above listed companies is organized and incorporated under the
laws of the State of South Carolina.

<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT

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 organization meeting, unless
the Board of Directors shall otherwise determine, or unless a resignation is
submitted.

Positions Held During
Name Age Past Five Years Dates

L.M. Gressette, Jr. 62 Chairman of the Board,
Chief Executive Officer
and President 1990-present
President 1989-1990

B.D. Kenyon 51 President and Chief
Operating Officer, SCE&G 1990-present
Senior Vice President -
Division Operations,
Pennsylvania Power and
Light Company *-1990

C.B. Novinger 44 Senior Vice President -
Administration *-present

W.B. Timmerman 47 Senior Vice President,
Chief Financial Officer
and Controller *-present

Max Earwood 61 President and Treasurer -
South Carolina Pipeline
Corporation *-present
President and Treasurer -
SCANA Hydrocarbons, Inc.;
SCANA Petroleum Resources,
Inc.; and Carolina
Exploration Corporation *-present
Vice President - Gas
Distribution, SCE&G *-1991

K.B. Marsh 38 Vice President - Finance,
Treasurer & Secretary 1992-present
Vice President of
Corporate Planning - SCE&G 1991
Vice President and
Controller - SCE&G 1989-1991

*Indicates position held at least since March 1, 1989

<PAGE>
<TABLE>
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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS

COMMON STOCK INFORMATION

1993 1992
4th 3rd 2nd 1st 4th 3rd 2nd 1st
Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr.
Price Range: (a)
High 52 1/4 51 7/8 48 3/8 46 1/2 43 1/8 44 3/4 41 3/4 44 3/8
Low 47 7/8 47 5/8 45 40 1/8 39 3/8 40 1/2 38 5/8 38 5/8

Dividends Per Share:

1993 Amount Date Declared Date Paid
First Quarter $.685 February 16, 1993 April 1, 1993
Second Quarter .685 April 29, 1993 July 1, 1993
Third Quarter .685 August 25, 1993 October 1, 1993
Fourth Quarter .685 October 19, 1993 January 1, 1994

1992 Amount Date Declared Date Paid
First Quarter $.67 February 18, 1992 April 1, 1992
Second Quarter .67 April 22, 1992 July 1, 1992
Third Quarter .67 August 26, 1992 October 1, 1992
Fourth Quarter .67 October 20, 1992 January 1, 1993

December 31,
1993 1992
Number of common shares outstanding 46,619,457 43,910,631
Number of common stockholders of record 41,564 42,937

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, 1994 was
46,884,903.

(a) As reported on the New York Stock Exchange Composite Listing.

SECURITIES RATINGS (As of December 31, 1993)

SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY
Rating First Mortgage First and Refunding Preferred Commercial
Agency Medium-Term Notes Bonds Mortgage Bonds Stock Paper

Duff &
Phelps NR A+ A+ A NR

Moody's A3 A1 A1 a1 P-1

Standard
& Poor's A- A A A- A-1

NR - Not Rated

Further reference is made to Note 5 of Notes to Consolidated Financial Statements.

ITEM 6. SELECTED FINANCIAL DATA

SELECTED FINANCIAL DATA
<S> <C> <C> <C> <C> <C> <C> <C>

For the Years Ended December 31, 1993 1992 1991 1990 1989 1983
Statement of Income Data (Thousands of Dollars except statistics and per share amounts)
Operating Revenues:

Electric $ 940,121 $ 829,477 $ 867,215 $ 851,146 $ 841,453 $636,319
Gas 320,195 305,275 276,742 292,380 297,069 337,282
Transit 3,851 3,623 3,869 4,033 4,102 3,242
Total Operating Revenues 1,264,167 1,138,375 1,147,826 1,147,559 1,142,624 976,843
Operating Expenses:

Fuel used in electric generation
and purchased power 241,745 213,474 234,683 223,972 241,352 272,716
Gas purchased for resale 209,743 191,577 171,869 191,939 212,112 277,091
Other operation and maintenance 290,891 281,242 270,213 265,887 249,464 125,231
Depreciation and amortization 112,844 108,315 102,669 97,801 102,296 45,000
Taxes 163,633 133,987 146,032 142,003 124,216 106,932
Total Operating Expenses 1,018,856 928,595 925,466 921,602 929,440 826,970
Operating Income 245,311 209,780 222,360 225,957 213,184 149,873
Other Income 30,076 11,883 11,655 54,874 7,125 11,571
Income Before Interest Charges and
Preferred Stock Dividends 275,387 221,663 234,015 280,831 220,309 161,444
Interest Charges, Net 101,189 97,600 91,458 92,317 90,421 57,506
Preferred Stock Cash Dividends of Subsidiary 6,217 6,473 6,706 6,911 7,263 17,186
Net Income $ 167,981 $ 117,590 $ 135,851 $ 181,603 $ 122,625 $ 86,752

Percent of Operating Income (Loss)
Before Income Taxes
Electric 90% 85% 89% 89% 91% 93
Gas 13% 18% 14% 14% 12% 10
Transit (3%) (3%) (3%) (3%) (3%) (3

Common Stock Data
Weighted Average Number of Common
Shares Outstanding (Thousands) 45,203 41,475 40,361 40,882 40,296 37,844
Earnings Per Weighted Average Share of Common Stock $3.72 $2.84 $3.37 $4.44 $3.04 $2.29
Dividends Declared Per Share of Common Stock $2.74 $2.68 $2.62 $2.52 $2.46 $2.00
Common Shares Outstanding (Year-End) (Thousands) 46,619 43,911 40,784 40,882 40,296 38,728
Book Value Per Share of Common Stock (Year-End) $28.59 $26.46 $25.23 $24.56 $22.79 $18.33

December 31, 1993 1992 1991 1990 1989 1983
Balance Sheet Data (Thousands of Dollars except statistics and per share amounts)

Utility Plant, Net $3,004,075 $2,810,279 $2,664,651$2,549,763 $2,444,278 $2,018,94

Total Assets $4,040,526 $3,557,721 $3,305,862$3,144,936 $2,984,507 $2,365,77

Common Equity $1,333,045 $1,161,896 $1,028,990$1,003,877 $ 918,235 $ 709,90
Preferred Stock (Not Subject to Purchase
or Sinking Fund Requirements) 26,027 26,027 26,02726,027 26,02726,262
Preferred Stock, Net (Subject to Purchase
or Sinking Fund Requirements) 52,840 56,154 59,46962,704 66,099157,589
Long-Term Debt, Net 1,424,399 1,204,754 1,122,396 938,933 1,003,972 796,518
Total Capitalization $2,836,311 $2,448,831 $2,236,882 $2,031,541 $2,014,333 $1,690,277

Other Statistics
Electric:
Customers (Year-End) 468,874 461,900 453,660 446,516435,004 366,
Territorial Sales (Million KWH) 16,880 15,794 15,69515,385 14,88512,063
Residential:
Average annual use per
customer (KWH) 14,077 13,037 13,24613,330 12,89112,009
Average annual rate
per KWH $.0707 $.0695 $.0700$.0707 $.0699$.0642
Generating Capability - Net MW (Year-End) 3,864 3,912 3,9123,891 3,8913,359
Territorial Peak Demand - Net MW 3,557 3,380 3,3003,222 3,1442,700

Gas:
Customers (Year-End) 234,736 231,153 225,819220,817 205,657187,638
Sales (Thousand Therms) 717,417 761,721 694,801711,821 714,585671,429
Residential:
Average annual use per
customer (therms) 605 577 521 497 575 610
Average annual rate
per therm $.76 $.74 $.77 $.77 $.69 $.65

Transit:
Number of Coaches 93 95 102 109 84 112
Revenue Passengers
Carried (Thousands) 4,568 5,837 6,395 6,788 6,430 9,744

</TABLE>

<PAGE>

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

LIQUIDITY AND CAPITAL RESOURCES

Due to continuing customer growth, SCE&G entered into a
contract with Duke/Fluor Daniel in 1991 to design, engineer and
build a 385 MW coal-fired electric generating plant near Cope,
South Carolina in Orangeburg County. Construction of the plant
began in November 1992 with commercial operation expected in late
1995 or early 1996. The estimated price of the Cope plant,
excluding financing costs and AFC but including an allowance for
escalation, is $450 million. In addition, the transmission lines
for interconnection with the Company's system are expected to
cost $26 million. Until the completion of the new plant, SCE&G
is contracting for additional capacity as necessary to ensure
that the energy demands of its customers can be met.

The estimated primary cash requirements for 1994, excluding
requirements for fuel liabilities and short-term borrowings, and
the actual primary cash requirements for 1993 are as follows:

1994 1993
(Thousands of Dollars)

Property additions and construction
expenditures, excluding allowance for
funds used during construction (AFC) $506,010 $381,141
Acquisition of oil and gas producing
properties - 122,621
Nuclear fuel expenditures 28,064 7,177
Maturing obligations, redemptions and
sinking and purchase fund requirements 25,627 16,530
Total $559,701 $527,469

Approximately 28% of total cash requirements (excluding
dividends) was provided from internal sources in 1993 as compared
to 40% in 1992.

<PAGE>

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 15 months prior to the month of issuance is at least twice
the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1993
the Bond Ratio was 3.70. The issuance of additional Class A
Bonds is restricted also to an additional principal amount equal
to 60% of unfunded net property additions (which unfunded net
property additions totaled approximately $219.9 million at
December 31, 1993), Class A Bonds issued on the basis of
retirements of Class A Bonds (which retirement credits totaled
$10.9 million at December 31, 1993), and Class A Bonds issued on
the basis of cash on deposit with the Trustee.

SCE&G has placed a new bond indenture (New Mortgage) dated
April 1, 1993 on substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are expected to be 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 $157 million
were available for such purpose as of December 31, 1993), until
such time as all presently outstanding Class A Bonds are retired.
Thereafter, New Bonds will be issuable on the basis of property
additions in a principal amount equal to 70% of the original cost
of electric and common plant properties (compared to 60% of value
for Class A Bonds under the Old Mortgage), cash deposited with
the Trustee, and retirement of New Bonds. New Bonds will be
issuable under the New Mortgage only if adjusted net earnings (as
therein defined) for 12 consecutive months out of the 18 months
immediately preceding the month of issuance are at least twice
the annual interest requirements on all outstanding bonds
(including Class A Bonds) and New Bonds to be outstanding (New
Bond Ratio). For the year ended December 31, 1993 the New Bond
Ratio was 5.0.

On April 29, 1993 the Securities and Exchange Commission
(SEC) declared effective a registration statement for the
issuance of up to $700 million of New Bonds. The following
series, aggregating $600 million, have been issued under such
registration statement:

On June 9, 1993, $100 million, 7 5/8% Series due June 1, 2023
to repay short-term borrowings in a like amount.

On July 1, 1993, $100 million, 6% Series due June 15,
2000; and $150 million, 7 1/8% Series due June 15, 2013; and
on July 20, 1993, $150 million, 7 1/2% Series due June
15, 2023, to redeem, on July 20, 1993, $382,035,000 of
First and Refunding Mortgage Bonds maturing between 1999 and
2017 and bearing interest at rates between 8% and 9 7/8% per
annum.

On December 20, 1993, $100 million, 6 1/4% Series due December
15, 2003 to repay short-term borrowings in a like amount.

<PAGE>

The following additional financing transactions have
occurred since December 31, 1992:

On June 1, 1993 SCE&G redeemed the following amounts of First
and Refunding Mortgage Bonds: $35 million, 10 1/8% Series
due 2009 and $13 million, 9 7/8% Series due 2009.

On July 1, 1993 the Company issued $60 million of medium-term
notes bearing interest at the following rates and maturing on
the following dates in the following amounts: $20 million,
5.76%, due July 1, 1998; $20 million, 6.15%, due July 3, 2000;
and $20 million, 6.51%, due July 1, 2003. The proceeds were
used to repay a portion of the 90-day bank loan discussed
above.

In early August 1993 the Company issued 1,467,000 shares of
common stock with net proceeds totaling $69,345,090. The
proceeds were used to repay the remainder of the 90-day bank
loan discussed above and for general corporate purposes.

On September 30, 1993 Pipeline Corporation sold unsecured
promissory notes totaling $25 million, 6.72% due September 30,
2013. The proceeds were used to repay short-term borrowings
in a like amount.

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 10% of the aggregate principal amount of all of
SCE&G's secured indebtedness and capital and surplus; provided,
however, that no such consent shall be 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
indebtedness. The FERC has authorized SCE&G to issue up to $200
million of unsecured promissory notes or commercial paper
with maturity dates of 12 months or less but not later than
December 31, 1995. GENCO has not sought such authorization.

The Company had $175.0 million authorized lines of credit
and had unused lines of credit of $148.0 million at December 31,
1993. In addition, the Company has a credit agreement for a
maximum of $75 million to finance nuclear and fossil fuel
inventories, with $38.2 million available at December 31,
1993.

<PAGE>

On October 12, 1993 the Company registered with the SEC
2,000,000 additional shares of the Company's common stock to be
issued and sold under the Dividend Reinvestment and Stock
Purchase Plan (DRP).

During 1993 the Company issued 529,954 shares of the
Company's common stock under the DRP. In addition, the Company
issued 705,498 shares of its common stock pursuant to its Stock
Purchase-Savings Plan (SPSP). The Company has authorized and
reserved for issuance, and registered under effective
registration statements, 2,065,824 and 872,420 shares of common
stock pursuant to the DRP and the SPSP, respectively.

In January 1994 the Company signed an agreement to sell in
1994 substantially all of the real estate assets of SCANA
Development Corporation (Development Corporation) to Liberty
Properties Group, Inc. of Greenville, South Carolina for $91.5
million. Under the terms of the agreement, a portion of the
sales price will be received in cash at the time of closing. The
remainder of the sales price, which is related to certain
projects currently under construction, will be received in cash
as those projects are completed. On March 4, 1994 the Company
and Liberty amended the agreement regarding the sale. Under the
terms of the amended agreement certain projects currently under
construction will be excluded from the transaction and the sales
price will be $49.6 million. All of the sales price will be
received at the time of closing. The net proceeds from the sale
will be used to retire Development Corporation's debt and for
general corporate purposes, including the funding of other
nonutility subsidiaries' business activities. The transaction
will not have a material impact on the Company's financial
position or results of operations.

The Company anticipates that its 1994 cash requirements of
$559.7 will be met through internally generated funds
(approximately 38% excluding dividends), the sales of additional
equity securities and the incurrence of additional short-term and
long-term indebtedness. The timing and amount of such financing
will depend upon market conditions and other factors. Actual
1994 expenditures may vary from the estimates set forth above due
to factors such as inflation and economic conditions, regulation
and legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.

The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirements.
Environmental Matters

The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by
the year 2000. These requirements are being phased in over two
periods. The first phase has a compliance date of January 1,
1995 and the second, January 1, 2000. The Company meets all
requirements of Phase I and therefore will not have to implement
changes until compliance with Phase II requirements is necessary.
The Company then will most likely meet its compliance
requirements through the burning of natural gas and/or lower
sulfur coal, the addition of scrubbers to coal-fired generating
units, and the purchase of sulfur dioxide emission allowances.
Low nitrogen oxide burners will be installed to reduce nitrogen
oxide emissions.

The Company is continuing to refine a compliance plan that
must be filed with the U.S. Environmental Protection Agency (EPA)
by January 1, 1996. The Company currently estimates that air
emissions control equipment will require capital expenditures of
$252 million over the 1994-1998 period to retrofit existing
facilities and an increased operation and maintenance cost
of $31 million per year. To meet compliance requirements through
the year 2003, the Company anticipates total capital expenditures
of $275 million.

<PAGE>

As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore actual expenditures could significantly
differ from the original estimates. Amounts estimated and
accrued to date ($19.6 million) for site assessments and cleanup
of regulated operations have been deferred and are being
amortized and recovered through rates over a ten-year period.
Estimates to date include, among other things, the costs
estimated to be associated with the matters discussed in the
following paragraphs.

The Company and its principal subsidiary, SCE&G, each own
two decommissioned manufactured gas plant sites which contain
residues of by-product chemicals. The Company and SCE&G have
each maintained an active review of their respective sites to
monitor the nature and extent of the residual contamination.

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
originally encompassed approximately 18 acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of SCE&G's
decommissioned manufactured gas plants. The original scope of
this investigation has been expanded to approximately 30 acres
including adjacent properties owned by the National Park Service
and the City of Charleston, and private properties. The site has
not been placed on the National Priority List, but may be added
before cleanup is initiated. The potentially responsible parties
(PRP) have agreed with the EPA to participate in an innovative
approach to site investigation and cleanup called "Superfund
Accelerated Cleanup Model," allowing the pre-cleanup site
investigations process to be compressed significantly. The PRPs
have negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study (RI/FS) and
a corresponding Scope of Work. Actual field work began November
1, 1993 after final approval and authorization was granted by
EPA. SCE&G is also working with the City of Charleston to
investigate potential contamination from the manufactured gas
plant at the city's aquarium site.

Litigation

In January 1994 SCE&G, acting on behalf of itself and the
PSA (as co-owners of Summer Station), reached a settlement with
Westinghouse Electric Corporation (Westinghouse) resolving a
dispute involving steam generators provided by Westinghouse to
Summer Station which are defective in design, workmanship and
materials. Terms of the settlement are confidential. SCE&G had
filed an action in May 1990 against Westinghouse in the U.S.
District Court for South Carolina; an order dismissing this suit
was issued on January 12, 1994.
33

<PAGE>

Regulatory Matters

On June 7, 1993 the PSC issued an order on SCE&G's pending
electric rate proceeding allowing an authorized return on common
equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually
on a test year basis. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, on a test year basis.

The Company's regulated business operations are likely to be
impacted by the National Energy Policy Act (NEPA) and FERC Order
No. 636. NEPA is designed to create a more competitive wholesale
power supply market by creating "exempt wholesale generators" and
by potentially requiring utilities owning transmission facilities
provide transmission access to wholesalers. Order No. 636 is
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.
In the opinion of the Company, it will be able to meet
successfully the challenges of these altered business climates.

Other

In November 1992 the Financial Accounting Standards Board
issued Statement No. 112 "Employers' Accounting for
Postemployment Benefits." The Statement, which is effective for
calendar year 1994, establishes certain conditions for the
recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition of the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered, the obligation relates to rights which vest, payment of
the benefits is probable and the amount of such benefits can be
reasonably estimated. The Company does not anticipate that
application of this Statement will have a significant impact on
results of operations or financial position.

RESULTS OF OPERATIONS

Earnings and Dividends

Earnings per share of common stock, the percent increase
(decrease) from the previous year and the rate of return earned
on common equity for the years 1991 through 1993 were as follows:

1993 1992 1991
Earnings per share $3.72 $2.84 $3.37
Percent increase (decrease) in earnings
per share 31.0% (15.7%) (24.1%)
Return earned on common equity (year-end) 12.6% 10.1% 13.2%

1993 Earnings per share and return on common equity increased
in 1993 primarily due to a higher electric sales margin and
additional nonoperating income.

1992 Earnings per share and return on common equity in 1992
decreased primarily due to the recording of an $11.1 million
(after interest and income taxes) reserve against earnings
related to the August 31, 1992 retail electric rate ruling
from the South Carolina Supreme Court (see Note 2F of Notes to
the Consolidated Financial Statements) and increases in other
operating and interest expenses.

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. Both an equity and debt portion of AFC are included
in nonoperating income as noncash items which have the effect of
increasing reported net income. AFC represented approximately
5.8% of income before income taxes in 1993, 5.5% in 1992 and 3.9%
in 1991.

<PAGE>

In 1993 the Company's Board of Directors raised the quarterly
cash dividend on common stock to 68.5 cents per share from 67
cents per share. The increase, effective with the dividend
payable on April 1, 1993, raised the indicated annual dividend
rate to $2.74 per share from $2.68. The Company has increased
the dividend rate on its common stock in 40 of the last 41 years.

Electric Operations

Electric sales margins for 1993, 1992 and 1991 were as
follows:

1993 1992 1991
(Millions of Dollars)

Electric revenues $940.1 $829.5 $867.2
Less: Fuel used in electric generation 228.7 206.2 224.9
Purchased power 13.0 7.3 9.8
Margin $698.4 $616.0 $632.5

1993 The increase in electric sales margin from 1992 to 1993
is primarilya result of increased residential and commercial
KWH sales due to weather and customer growth, an increase in
retail electric rates beginning in June 1993 and the recording
in 1992 of a $14.6 million reserve as discussed below.

1992 The 1992 electric sales margin decreased from 1991 due
to therecording of a $14.6 million reserve, before interest
and income taxes, related to the August 31, 1992 ruling from
the South Carolina Supreme Court (see Note 2F of Notes to
Consolidated Financial Statements) and a $1.9 million billing
related litigation settlement included in 1991 electric
operating revenues.

Warmer weather and an increase in the number of electric
customers resulted in an all-time peak demand record of 3,557 MW
on July 29, 1993. The previous year's record of 3,380 MW was set
on July 13, 1992.

Gas Operations

Gas sales margins for 1993, 1992 and 1991 were as follows:

1993 1992 1991
(Millions of Dollars)

Gas revenues $320.2 $305.3 $276.7
Less: Gas purchased for resale 209.7 191.6 171.9
Margin $110.5 $113.7 $104.8

1993 In 1993 the gas sales margin decreased from 1992 as a
result of higher gas prices which reduced Pipeline
Corporation's sales due to the competitiveness of alternative
fuels. This reduction was partially offset by increases in
higher margin residential and commercial sales and increased
transportation volumes.

1992 The gas sales margin for 1992 increased from 1991 as a
result of recoveries of $4.2 million allowed under a weather
normalization adjustment which became effective the first
billing cycle in December 1991; increases in residential usage
due to cooler weather during 1992; and increased
transportation volumes.

<PAGE>

Other Operating Expenses and Taxes

Increases (decreases) in other operating expenses, including
taxes, are presented in the following table:

Increase (Decrease)
From Prior Year
Classification 1993 1992
(Millions of Dollars)

Other operation and maintenance $ 9.6 $ 11.0
Depreciation and amortization 4.5 5.6
Income taxes 29.1 (16.6)
Other taxes .6 4.6
Total $43.8 $ 4.6

, 1993 Other operation and maintenance expenses increased for
1993 primarily due to the implementation of Financial
Accounting Standards Board Statement No. 106 (see Note 1J of
Notes to Consolidated Financial Statements) pursuant to the
June 1993 PSC electric rate order and the amortization of
environmental expenses. The depreciation and amortization
increase reflects additions to plant in service. The increase
in income taxes corresponds to the increase in income and
reflects the increase in the corporate tax rate from 34% to
35% retroactive to January 1, 1993.

1992 Other operation and maintenance expenses increased for
1992 primarily due to increases in administrative and general
expenses, increases in nuclear regulatory fees and nuclear and
transmission systems maintenance. The increase in
depreciation and amortization expense reflects additions to
plant in service. Income taxes decreased primarily due to the
tax impact of the rate refund (see Note 2F of Notes to
Consolidated Financial Statements) and to other decreases in
income. Other taxes increased primarily from higher property
taxes caused by property additions and increased millage
rates. In addition to the above, other taxes increased due to
increases in state license fees.

Other income, net of income taxes, increased approximately
$14.7 million in 1993 primarily due to additional income from
Petroleum Resources related to higher natural gas prices and
additional income resulting from the acquisition of NICOR in June
1993.

Interest Expense

Increases (decreases) in interest expense are presented in
the following table:

Increase (Decrease)
From Prior Year
Classification 1993 1992
(Millions of Dollars)

Interest on long-term debt, net $5.6 $4.3
Other interest expense (.1) 1.2
Total $5.5 $5.5

<PAGE>

1993 Interest on long-term debt increased approximately $5.6
million in 1993 compared to 1992 due to the issuance of $72.4
million medium-term notes during the latter part of 1992 and
$60 million medium-term notes in July 1993 to finance
acquisitions of natural gas reserves and the issuance of $200
million of SCE&G's First Mortgage Bonds to finance utility
construction. The resulting increases more than offset the
interest savings resulting from the redemption and
refinancing of $382 million of First and Refunding
Mortgage Bonds with the proceeds from the issuance of $400
million of First Mortgage Bonds by SCE&G at lower interest
rates.

1992 Interest on long-term debt increased approximately $4.4
million in 1992 compared to 1991 due to the issuances
of $145 million and $155 million of First and Refunding
Mortgage Bonds on July 24, 1991 and August 29, 1991,
respectively, which more than offset the decreases in interest
expense resulting from the repayment of debt and lower
interest rates on remaining debt.

<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA

Page

Independent Auditor's Report....................................... 39

Consolidated Financial Statements:

Consolidated Balance Sheets as of December 31, 1993 and 1992... 40

Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1993, 1992 and 1991............. 42

Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 1992 and 1991............................. 43

Consolidated Statements of Capitalization as of
December 31, 1993 and 1992................................... 44

Notes to Consolidated Financial Statements..................... 46

Supplemental Financial Statement Schedules:

Schedule V - Property, Plant and Equipment for the
years ended December 31, 1993, 1992 and 1991................. 65

Schedule VI - Accumulated Depreciation and Amortization
of Property, Plant and Equipment for the years
ended December 31, 1993, 1992 and 1991....................... 68

Schedule X - Supplementary Income Statement
Information for the years ended
December 31, 1993, 1992 and 1991............................. 71

Supplemental financial statement schedules other than those listed above
are omitted because of the absence of conditions under which they are required
or because the required information is included in the consolidated financial
statements or in the notes thereto.

<PAGE>

INDEPENDENT AUDITORS' REPORT

SCANA CORPORATION:

We have audited the accompanying Consolidated Balance Sheets
and Consolidated Statements of Capitalization of SCANA
Corporation and subsidiaries (Company) as of December 31, 1993
and 1992 and the related Consolidated Statements of Income and
Retained Earnings and of Cash Flows for each of the three years
in the period ended December 31, 1993. Our audits also included
the financial statement schedules listed in the index on page 38.
These financial statements and financial statement schedules are
the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.

We conducted our audits in accordance with generally
accepted auditing standards. 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, 1993 and 1992, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1993 in conformity with generally
accepted accounting principles. Also, in our opinion, such
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.

s/Deloitte & Touche
DELOITTE & TOUCHE
Columbia, South Carolina
February 7, 1994

39
<PAGE>

CONSOLIDATED BALANCE SHEETS

December 31, 1993 1992
ASSETS (Thousands of Dollars)
Utility Plant (Notes 1, 3 and 4):
Electric $3,328,915 $3,203,849
Gas 451,493 411,584
Transit 3,769 3,287
Common 72,804 65,124
Total 3,856,981 3,683,844
Less accumulated depreciation and amortization 1,259,689 1,192,873
Total 2,597,292 2,490,971
Construction work in progress 349,530 250,229
Nuclear fuel, net of accumulated amortization 29,087 39,916
Acquisition adjustment-gas, net of accumulated amortization 28,166 29,163
Utility Plant, Net 3,004,075 2,810,279

Nonutility Property and Investments (net of accumulated
depreciation and depletion)(Note 8) 393,728 250,084

Current Assets:
Cash and temporary cash investments (Note 8) 20,766 32,050
Receivables 174,121 138,684
Inventories (at average cost):
Fuel (Notes 3 and 4) 62,977 52,598
Materials and supplies 46,890 46,274
Prepayments 21,826 22,628
Accumulated deferred income taxes 8,607 -
Total Current Assets 335,187 292,234

Deferred Debits:
Unamortized debt expense 13,076 10,104
Accumulated deferred income taxes (Notes 1 and 7) - 45,599
Unamortized deferred return on plant investment (Note 1) 14,860 19,106
Nuclear plant decommissioning fund (Note 1) 25,103 20,841
Other (Notes 1 and 10) 254,497 109,474
Total Deferred Debits 307,536 205,124

Total $4,040,526 $3,557,721

December 31, 1993 1992
CAPITALIZATION AND LIABILITIES (Thousands of Dollars)

Stockholders' Investment (Note 5):
Common equity $1,333,045 $1,161,896
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,359,072 1,187,923
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 52,840 56,154
Long-Term Debt, Net (Notes 3, 4 and 8) 1,424,399 1,204,754
Total Capitalization 2,836,311 2,448,831

Current Liabilities:
Short-term borrowings (Notes 8 and 9) 43,019 41,156
Current portion of long-term debt (Note 3) 34,322 24,704
Current portion of preferred stock (Note 6) 2,504 2,485
Accounts payable 129,495 101,785
Estimated rate refunds and related interest (Note 2) 2,509 17,811
Customer deposits 13,498 14,102
Taxes accrued 50,063 65,004
Interest accrued 21,784 29,295
Dividends declared 33,637 31,302
Other 12,649 8,438
Total Current Liabilities 343,480 336,082

Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 568,172 539,439
Accumulated deferred investment tax credits (Notes 1 and 7) 94,981 98,639
Accumulated reserve for nuclear plant decommissioning (Note 1) 25,103 20,841
Other (Note 1) 172,479 113,889
Total Deferred Credits 860,735 772,808

Commitments and Contingencies (Note 10) - -

Total $4,040,526 $3,557,721

See Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars
except per share amounts)
Operating Revenues (Notes 1 and 2):
Electric $ 940,121 $ 829,477 $ 867,215
Gas 320,195 305,275 276,742
Transit 3,851 3,623 3,869
Total Operating Revenues 1,264,167 1,138,375 1,147,826

Operating Expenses:
Fuel used in electric generation 228,688 206,151 224,867
Purchased power 13,057 7,323 9,816
Gas purchased for resale 209,743 191,577 171,869
Other operation (Note 1) 223,239 215,800 208,614
Maintenance (Note 1) 67,652 65,442 61,599
Depreciation and amortization (Note 1) 112,844 108,315 102,669
Income taxes (Notes 1 and 7) 90,007 60,947 77,562
Other taxes 73,626 73,040 68,470
Total Operating Expenses 1,018,856 928,595 925,466
Operating Income 245,311 209,780 222,360

Other Income (Note 1):
Other income, net of income taxes 21,147 6,388 8,201
Allowance for equity funds used during construction 8,929 5,495 3,454
Total Other Income 30,076 11,883 11,655

Income Before Interest Charges
and Preferred Stock Dividends 275,387 221,663 234,015

Interest Charges (Credits):
Interest on long-term debt, net 98,695 93,052 88,690
Other interest expense 8,672 8,819 7,648
Allowance for borrowed funds used
during construction (Note 1) (6,178) (4,271) (4,880)
Total Interest Charges, Net 101,189 97,600 91,458

Income Before Preferred Stock Cash
Dividends of Subsidiary 174,198 124,063 142,557

Preferred Stock Cash Dividends of
Subsidiary (At stated rates) (6,217) (6,473) (6,706)

Net Income 167,981 117,590 135,851
Retained Earnings at Beginning of Year 462,893 457,393 428,626
Common Stock Cash Dividends Declared (Note 5) (124,494) (112,090) (105,868)
Other - - (1,216)

Retained Earnings at End of Year $ 506,380 $ 462,893 $ 457,393

Net Income $ 167,981 $ 117,590 $ 135,851
Weighted Average Number of Common Shares
Outstanding (Thousands) 45,203 41,475 40,361
Earnings Per Weighted Average Share of Common Stock $3.72 $2.84 $3.37

See Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 1993 1992 1991
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $167,981 $117,590 $135,851
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization 158,024 126,695 117,402
Amortization of nuclear fuel 18,156 23,190 18,384
Deferred income taxes, net 65,205 (10,783) 30,199
Deferred investment tax credits, net (3,658) (3,667) (3,646)
Net regulatory asset - adoption of SFAS No. 109 (31,531) - -
Dividends declared on preferred stock of subsidiary 6,217 6,473 6,706
Allowance for funds used during construction (15,107) (9,766) (8,334)
Unamortized loss on reacquired debt (17,063) (81) 171
Nuclear refueling accrual (6,086) 11,862 (6,192)
Equity in (earnings) losses of investees (319) 652 412
Over (under) collections, fuel adjustment clause (14,308) 7,482 (1,207)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (35,244) (8,918) (2,506)
(Increase) decrease in inventories (10,995) (234) 7,785
Increase (decrease) in accounts payable 28,109 7,282 6,978
Increase (decrease) in estimated rate
refunds and related interest (15,302) 17,811 -
Increase (decrease) in taxes accrued (14,941) 1,691 9,095
Increase (decrease) in interest accrued (7,511) 663 4,410
Other, net 3,955 12,354 3,567
Net Cash Provided From Operating Activities 275,582 300,296 319,075
Cash Flows From Investing Activities:
Utility property additions and construction expenditures (322,381) (277,636) (239,140)
Increase in nonutility property and investments:
Acquisition of oil and gas producing properties (122,621) (74,766) (3,167)
Nonutility property (81,044) (35,462) (20,750)
Investments (4,066) (2,591) 4,895
Repurchase/reissuance of common stock for
immaterial acquisition, net of cash acquired - - (25,514)
Principal noncash item:
Allowance for funds used during construction 15,107 9,766 8,334
Net Cash Used For Investing Activities (515,005) (380,689) (275,342)
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds 600,000 - 300,000
Issuance of common stock 129,066 126,809 -
Issuance of notes 85,000 150,900 -
Issuance of bank notes and loans 63,059 3,354 80,000
Other long-term debt 3,005 - -
Repayments:
Mortgage bonds (430,000) (35,890) (8,000)
Notes (71,700) (95,217) (81,016)
Other long-term debt (1,535) (310) (76,649)
Repurchase of common stock - - (3,656)
Preferred stock (3,295) (3,199) (2,622)
Dividend payments:
Common stock (122,129) (109,383) (104,910)
Preferred stock (6,247) (6,558) (6,718)
Short-term borrowings, net 1,863 20,390 (113,304)
Fuel financings, net (18,948) (6,628) (4,292)
Net Cash Provided By (Used For) Financing Activities 228,139 44,268 (21,167)
Net Increase (Decrease) in Cash and Temporary Cash Investments (11,284) (36,125) 22,566
Cash and Temporary Cash Investments, January 1 32,050 68,175 45,609
Cash and Temporary Cash Investments, December 31 $ 20,766 $ 32,050 $ 68,175

Supplemental Cash Information:
Cash paid for - Interest $113,010 $100,340 $ 90,623
- Income taxes 93,337 81,819 45,357

Noncash Financing Activities:
Capital lease obligations recorded - - 2,864
Department of Energy Decontamination and
Decommissioning Obligation 4,965 - -

See Notes to Consolidated Financial Statements.

<PAGE>

CONSOLIDATED STATEMENTS OF CAPITALIZATION
<S> <C> <C> <S> <C> <C> <S> <C> <C>

December 31, 1993 1992
Common Equity (Note 5): (Thousands of Dollars)
Common stock, without par value, authorized 75,000,000 shares; issued
and outstanding, 1993 - 46,619,457 shares and 1992 - 43,910,631 shares $ 826,665 $ 699,003
Retained earnings 506,380 462,893
Total Common Equity 1,333,045 47% 1,161,896 48%

South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5):

$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares

Shares Outstanding Redemption Price
Eventual
Series 1993 1992 Current Through Minimum
$100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767
$ 50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1%

South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8):

$100 Par Value - Authorized 1,550,000 shares

Shares Outstanding Redemption Price
Eventual
Series 1993 1992 Current Through Minimum
7.70% 92,992 96,000 101.00 - 101.00 9,299 9,600
8.12% 131,899 136,265 102.03 - 102.03 13,190 13,626
224,891 232,265

$ 50 Par Value - Authorized 1,639,886 shares

Shares Outstanding Redemption Price
Eventual
Series 1993 1992 Current Through Minimum
4.50% 20,800 22,400 51.00 - 51.00 1,040 1,120
4.60% 3,834 5,334 50.50 - 50.50 192 267
4.60%(A) 30,052 32,052 51.00 - 51.00 1,503 1,602
4.60%(B) 81,600 85,000 50.50 - 50.50 4,080 4,250
5.125% 74,000 75,000 51.00 - 51.00 3,700 3,750
6.00% 89,600 92,800 50.50 - 50.50 4,480 4,640
8.72% 160,000 192,000 51.00 12-31-98 50.00 8,000 9,600
9.40% 197,191 203,678 51.175 - 51.175 9,860 10,184
657,077 708,264

$ 25 Par Value - Authorized 2,000,000 shares; None outstanding in 1993 and 1992

Total Preferred Stock (Subject to purchase or sinking funds) 55,344 58,639
Less: Current portion, including sinking fund requirements 2,504 2,485
Total Preferred Stock, Net (Subject to purchase or sinking funds) 52,840 2% 56,154 2%

<PAGE>

December 31, 1993 1992
Long-Term Debt (Notes 3, 4 and 8): (Thousands of Dollars)

SCANA Corporation:
Bank Notes, due 1995 (various rates between 3.875% and 3.89%) 60,000 60,000
Medium-term Notes:
Year of
Series Maturity

5.76% 1998 20,000 -
7.17% 1999 42,400 42,400
6.60% 1999 30,000 30,000
6.15% 2000 20,000 -
6.51% 2003 20,000 -

South Carolina Electric & Gas Company:
First Mortgage Bonds:
Year of
Series Maturity

6% 2000 100,000 -
6 1/4% 2003 100,000 -
7 1/8% 2013 150,000 -
7 1/2% 2023 150,000 -
7 5/8% 2023 100,000 -

First and Refunding Mortgage Bonds:
Year of
Series Maturity

4 7/8% 1995 16,000 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
8% 1999 - 35,000
9 1/8% 1999 - 15,000
8% 2001 - 35,000
7 1/4% 2002 30,000 30,000
9% 2006 145,000 145,000
9 1/8% 2006 - 50,000
8.40% 2006 - 50,000
8 3/8% 2007 - 30,000
8.90% 2008 - 30,000
10 1/8% 2009 - 35,000
9 7/8% 2009 - 50,000
8 3/4% 2017 - 100,000
8 7/8% 2021 155,000 155,000

Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,760 6,855
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Capitalized Lease Obligations, due 1991-1997 (various rates between
5 3/4% and 10%) 2,897 4,875
Installment Note Payable, due 1996 2,277 -
Department of Energy Decontamination and Decommissioning Obligation 4,634 -
South Carolina Generating Company, Inc.:
Berkeley County Pollution Control
Facilities Revenue Bonds, due 2014 (6.50%) 35,850 35,850
Note, 7.78%, due 2011 71,100 74,800
South Carolina Fuel Company, Inc.:
Nuclear and Fossil Fuel Liability 36,750 55,698
South Carolina Pipeline Corporation:
Notes, 6.72% due 2013 25,000 -
Note, 9.27%, due 1991-1994 8,000 16,000
SCANA Development Corporation, Inc.:
Notes, due 1994-2004 (various rates between 8.5% and 12.0%) 1,770 1,384
Bank Loans, due 1994-1998 (various rates between 6% and 6.25%) 13,839 10,952
Primesouth:
Term Loan and Capitalized Lease Obligation - 902
Total Long-Term Debt 1,464,762 1,233,201
Less - Current maturities, including sinking fund requirements 34,322 24,704
- Unamortized discount 6,041 3,743
Total Long-Term Debt, Net 1,424,399 50% 1,204,754 49%
Total Capitalization $2,836,311 100% $2,448,831 100%
See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

A. Organization and Principles of Consolidation

SCANA Corporation (Company), a South Carolina corporation, is
a public utility holding company within the meaning of the Public
Utility Holding Company Act of 1935, but is exempt from
registration under such Act.

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

Regulated utilities

South Carolina Electric & Gas Company (SCE&G)
South Carolina Fuel Company, Inc.
South Carolina Generating Company, Inc. (GENCO)
South Carolina Pipeline Corporation (Pipeline Corporation)

Nonregulated businesses

SCANA Petroleum Resources, Inc. (Petroleum Resources)
SCANA Hydrocarbons, Inc.
Suburban Propane Group, Inc.
SCANA Development Corporation
MPX Systems, Inc.
Primesouth, Inc.
SCANA Capital Resources, Inc.

Investments in joint ventures in real estate are reported
using the equity method of accounting. Significant intercompany
balances and transactions have been eliminated in consolidation.

In January 1994 the Company signed an agreement to sell in
1994 substantially all of the real estate assets of SCANA
Development Corporation to Liberty Properties Group, Inc. of
Greenville, South Carolina for $91.5 million. Under the terms of
the agreement, a portion of the sales price will be received in
cash at the time of closing. The remainder of the sales price,
which is related to certain projects currently under
construction, will be received in cash as those projects are
completed. The transaction will not have a material impact on
results of operations.

B. System of Accounts

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

C. 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.

<PAGE>

SCE&G, operator of the V. C. Summer Nuclear Station (Summer
Station), and the South Carolina Public Service Authority (PSA)
are joint owners of Summer Station in the proportions of two-
thirds and one-third, respectively. The parties share the op-
erating 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 $920.2 million and $916.0 million as of
December 31, 1993 and 1992, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was
approximately $285.3 million and $262.2 million as of December
31, 1993 and 1992, respectively. SCE&G's share of the direct
expenses associated with operating Summer Station is included in
the Company's "Other operation" and "Maintenance" expenses.

D. Allowance for Funds Used During Construction

Allowance for funds used during construction (AFC), a
noncash item, reflects the period cost of capital devoted to
plant under construction. This accounting practice results in
the inclusion, as a component of construction cost, of 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 9.3%, 9.6% and 9.7% for 1993, 1992 and
1991, 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.

E. Deferred Return on Plant Investment

Commencing July 1, 1987, as approved by a PSC order on that
date, SCE&G ceased the deferral of carrying costs associated with
400 MW of electric generating capacity previously removed from
rate base and began amortizing the accumulated deferred carrying
costs on a straight-line basis over a ten-year period.
Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1993, 1992 and 1991.

F. Revenue Recognition

Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.

Fuel costs for electric generation are collected through the
fuel component in retail electric rates. The fuel component
contained in electric rates is established by the PSC during
semiannual fuel cost hearings. Any difference between actual
fuel cost and that contained in the fuel component is deferred
and included when determining the fuel cost component during the
next semiannual fuel cost hearing. At December 31, 1993 and 1992
SCE&G had overcollected through the electric fuel clause
component approximately $9.2 million and $17.7 million,
respectively, which are included in "Deferred Credits-Other."

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
cost and that contained in the rates is deferred and included
when establishing gas costs during the next annual gas cost
recovery hearing. At December 31, 1993 and 1992 the Company had
undercollected through the gas cost recovery procedure
approximately $12.0 million and $6.2 million, respectively, which
are included in "Deferred Debits-Other."

<PAGE>

G. Depreciation, Depletion and Amortization

Provisions for depreciation are recorded using the straight-
line method for financial reporting purposes and are based on the
estimated service lives of the various classes of property. The
composite weighted average depreciation rates were as follows:

<TABLE>

1993 1992 1991
SCE&G 2.97% 3.00% 2.97%
GENCO 2.64% 2.63% 2.59%
Pipeline Corporation 2.62% 2.62% 2.62%
Aggregate of Above 2.92% 2.96% 2.94%

Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is 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 United
States Department of Energy 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.

Depreciation, depletion and amortization of the capitalized
costs of oil and gas producing properties is provided for on the
units-of-production basis. Units-of-production rates are based
on estimated proven reserves.

H. Nuclear Decommissioning

Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
The expenditures (on a before-tax basis) related to SCE&G's share
of decommissioning activities are currently estimated, in 2022
dollars assuming a 4.5% annual rate of inflation, to be
approximately $545.3 million including partial reclamation costs.
SCE&G is providing for its share of estimated decommissioning
costs of Summer Station over the life of Summer Station. SCE&G
collected through rates $2.5 million and $1.6 million in 1993 and
1992, respectively. The amounts collected are deposited in an
external trust fund in compliance with the financial assurance
requirements of the Nuclear Regulatory Commission. Management
intends for the fund, including earnings thereon, to provide for
all eventual decommissioning expenditures on an after-tax basis.

In addition, pursuant to the National Energy Policy Act
passed by Congress in 1992, SCE&G has recorded a liability for
its estimated share of amounts required by the U.S. Department of
Energy for its decommissioning fund. SCE&G will recover the
costs associated with this liability, totaling $4.6 million at
December 31, 1993, through the fuel cost component of its rates;
accordingly, these amounts have been deferred and are included in
"Deferred Debits-Other" and "Long-term Debt, Net."

I. Income Taxes

The Company and its subsidiaries file consolidated Federal
and State income tax returns. Income taxes are allocated to all
subsidiaries based on their contributions to consolidated taxable
income.

<PAGE>

The Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," effective
January 1, 1993. Prior years' financial statements have not been
restated. Deferred tax assets and liabilities were adjusted from
the amounts recorded at December 31, 1992 under prior standards
to the amounts required at January 1, 1993 under Statement No.
109 at currently enacted income tax rates. The adjustments were
charged or credited to regulatory assets or liabilities if the
Company expects to recover the resulting additional income tax
expense from, or pass through the resulting reductions in income
tax expense to, customers of the Company's regulated
subsidiaries; otherwise they were charged or credited to income
tax expense. The cumulative effect of adopting Statement No. 109
on retained earnings as of January 1, 1993, as well as the effect
of adoption on net income for the year ended December 31, 1993,
was not material. The combined effect of adopting Statement No.
109 and adjusting deferred tax assets and liabilities for the
change in 1993 of the corporate Federal income tax rate from 34%
to 35% resulted in balances of $100.8 million in regulatory
assets (included in "Deferred Debits-Other") and $69.3 million in
regulatory liabilities (included in "Deferred Credits-Other") for
the Company's regulated subsidiaries.

In accordance with Statement No. 109, deferred tax assets
and liabilities are recorded for the tax effect of temporary
differences between the book 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.

Prior to the adoption of Statement No. 109 on January 1,
1993, the Company recorded a deferred income tax provision on all
material timing differences between the inclusion of items in
pretax financial income and taxable income each year, except for
those which were expected to be passed through to, or collected
from, customers of the Company's regulated subsidiaries.
Accumulated deferred income taxes were generally not adjusted for
changes in enacted tax rates.

J. Pension Expense

The Company has a noncontributory defined benefit pension
plan covering substantially all permanent employees. Benefits
are based on years of accredited service and the employee's
average annual base earnings received during the last three years
of employment. The Company's policy has been to fund pension
costs accrued to the extent permitted by the applicable Federal
income tax regulations as determined by an independent actuary.

Net periodic pension cost, as determined by an
independent actuary, for the years ended December 31, 1993,
1992 and 1991 included the following components:

1993 1992 1991
(Thousands of Dollars)
Service cost-benefits earned during the period $ 7,629 $ 7,174 $ 6,367
Interest cost on projected benefit obligation 20,413 19,628 18,334
Adjustments: Return on plan assets (50,389) (28,607) (51,440)
Net amortization and deferral 25,936 8,096 36,263
Net periodic pension cost $ 3,589 $ 6,291 $ 9,524

<PAGE>

The following table sets forth the funded status of the plan, as
determined by an independent actuary, at December 31, 1993 and 1992:

1993 1992
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $204,794 $177,930
Nonvested benefit obligation 14,085 17,110
Accumulated benefit obligation $218,879 $195,040

Projected benefit obligation $295,718 $258,440
Plan assets at fair value
(invested primarily in equity
and debt securities) 351,648 304,114
Plan assets greater than
projected benefit obligation 55,930 45,674
Unrecognized net transition liability 10,713 11,555
Unrecognized prior service costs 9,294 10,563
Unrecognized net gain (64,607) (63,633)
Pension asset recognized in
Consolidated Balance Sheets $ 11,330 $ 4,159

The accumulated benefit obligation is based on the plan's benefit formulas
without considering expected future salary increases. The following
table sets forth the assumptions used in the amounts shown above for the
years 1993, 1992 and 1991.

1992 and
1993 1991

Annual discount rate used to determine benefit obligations 7.25% 8.0%
Expected long-term rate of return on plan assets 7.25% 8.0%
Discount rate used in determining pension cost 8.0% 8.0%
Assumed annual rate of future salary increases for projected
benefit obligation 4.75% 5.5%

The change in the annual discount rate used to determine
benefit obligations from 8.0% to 7.25% as of December 31, 1993
increased the projected benefit obligation and reduced the
unrecognized net gain by approximately $4.1 million.

In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. On January 1, 1993 the Company adopted
Statement No. 106 "Employers' Accounting for Postretirement
Benefits Other Than Pensions." The Statement requires that the
cost of postretirement benefits other than pensions be accrued
during the years the employees render the service necessary to be
eligible for the applicable benefits. The Company previously
expensed these benefits, which are primarily health care, as
claims were incurred. The accumulated obligation for these
benefits at January 1, 1993 was approximately $68 million
(transition liability) and the annualized increase in expenses
(net of payments to current retirees), including the amortization
of the transition liability over approximately 20 years as
provided for by the Statement, is approximately $4.7 million. In
its June 1993 electric rate order (see Note 2A) the PSC approved
the inclusion in rates of the portion of increased expenses
related to electric operations. Such expenses had been deferred
through May 31, 1993 pursuant to a December 10, 1992 accounting
directive allowing deferral pending consideration of recovery in
future rate proceedings. The Company expensed approximately $4.3
million, net of payments to current retirees, for the year ended
December 31, 1993.

<PAGE>

Net periodic postretirement benefit cost, as determined by an independent
actuary for the year ended December 31, 1993 included the following
components (thousands of dollars):

Service cost-benefits earned during the period $ 1,908
Interest cost on accumulated postretirement benefit
obligation 5,502
Adjustments: Return on plan assets -
Amortization of unrecognized transition
obligation 3,344
Other net amortization and deferral -
Net periodic postretirement benefit cost $ 10,754

The following table sets forth the unfunded status of the plan, as determined
by an independent actuary, at December 31, 1993 (thousands of dollars):

Accumulated postretirement benefit obligations for:
Retirees $ 40,865
Other fully eligible participants 25,767
Other active participants 6,841
Accumulated postretirement benefit obligation 73,473
Plan assets at fair value -
Plan assets less accumulated postretirement benefit
obligation (73,473)
Unrecognized net transition liability 64,925
Unrecognized prior service costs -
Unrecognized net (gain) loss 4,248
Postretirement benefit liability recognized
in Consolidated Balance Sheet $ (4,300)

The accumulated postretirement obligation is based upon the plan's benefit
provisions and the following assumptions:

Assumed health care cost trend rate used to
measure expected 1994 costs 12.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.25%
Discount rate used in determining post-
retirement benefit costs 7.25%
Assumed annual rate of salary increases 4.75%

The effect of a one-percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31, 1993
and the accumulated postretirement benefit obligation as of
December 31, 1993 would be to increase such amounts by $60,000
and $1.7 million, respectively.

<PAGE>

K. 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.

L. Environmental

The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore actual expenditures could significantly
differ from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period. Such amounts totaled $19.6 million and $18.3
million at December 31, 1993 and 1992, respectively, and are
included in "Deferred Debits-Other."

M. Gas Futures Contracts

The Company sells gas futures contracts to hedge price risks
for a portion of Petroleum Resources' production. Gains and
losses on such contracts, which are not material, are recognized
concurrently with the revenue from the associated gas sales.

N. Postemployment Benefits

In November 1992 the Financial Accounting Standards Board
issued Statement No. 112 "Employers' Accounting for
Postemployment Benefits." The Statement, which is effective for
calendar year 1994, establishes certain conditions for the
recognition of costs of benefits to former employees after
employment but before retirement. The Statement requires
recognition of the obligation to provide postemployment benefits
if such obligation is attributable to services previously
rendered, the obligation relates to rights which vest, payment of
the benefits is probable, and the amount of such benefits can be
reasonably estimated. The Company does not anticipate that
application of this Statement will have a significant impact on
results of operations or financial position.

O. 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.

P. Reclassifications

Certain amounts from prior periods have been reclassified to
conform with the 1993 presentation.

2. RATE MATTERS:

A. On June 7, 1993 the PSC issued an order on the Company's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually
based on a test year. These rates are to be implemented in two
phases over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, based on a test year.

<PAGE>

B. On September 14, 1992 the PSC issued an order granting
SCE&G a $.25 increase in transit fares from $.50 to $.75 in both
Columbia and Charleston, 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 on October
5, 1992. SCE&G has appealed the PSC's order to the Circuit
Court. During oral arguments in February 1994 the Circuit Court
retained jurisdiction and remanded the decision to the PSC for
the limited purpose of answering questions concerning the
applicable regulatory principles used by the PSC in determining
these transit rates.

C. Since November 1, 1991 SCE&G's gas rate schedules for its
residential, small commercial and small industrial customers have
included a weather normalization adjustment (WNA). The WNA
minimizes fluctuations in gas revenues due to abnormal weather
conditions and has been approved through November 1994 subject to
an annual review by the PSC. The PSC order was based on a
return on common equity of 12.25% (see Note 2G). The WNA became
effective the first billing cycle in December 1991.

D. In May 1989 the PSC approved a volumetric and direct
billing method for Pipeline Corporation to recover take-or-pay
costs incurred from its interstate pipeline suppliers pursuant
to FERC-approved final and non-appealable settlements. In
December 1992 the South Carolina Supreme Court (Supreme Court)
approved Pipeline Corporation's full recovery of the take-or-pay
charges imposed by its suppliers and treatment of these charges
as a cost of gas. However, the Supreme Court declared the PSC-
approved "purchase deficiency" methodology for recovery of these
costs to be unlawful retroactive ratemaking and remanded the
docket to the PSC to reconsider its recovery methodology. The
Company believes that the elimination of the purchase deficiency
method of recovery will affect the timing for recovery of take-
or-pay charges and shift the allocations among Pipeline
Corporation's customers (including SCE&G) but that all such
charges should be ultimately recovered. The case has been
remitted to the PSC by the Supreme Court and the Company
anticipates the PSC will issue an Order authorizing full recovery
of incurred take-or-pay costs on a prospective volumetric basis
after the completion of accounting verification by the PSC Staff
of the principal and associated interest costs.

E. On August 8, 1990 the PSC issued an order, effective
November 1, 1990, approving changes in Pipeline Corporation's gas
rate design for sales for resale service and upholding the
"value-of-service" method of regulation for its direct industrial
service. Direct industrial customers seeking "cost-of-service"
based rates initiated two separate appeals to the Circuit Court,
which reversed and remanded to the PSC its August 8, 1990 order.
Pipeline Corporation appealed that decision to the Supreme Court
which reversed the two Circuit Court decisions and reinstated the
PSC Order. The Supreme Court held that the industrial customer
group's appeal was premature and failed to exhaust administrative
remedies. Additionally, the Supreme Court interpreted the rate-
making statutes of South Carolina to give discretion to the PSC
in selecting the methodology to be used in setting rates for
natural gas service.

F. On July 3, 1989 the PSC granted SCE&G approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity
of 13.25%. The Consumer Advocate appealed the decision to the
Supreme Court which, on August 31, 1992, found that the evidence
in the record of that case did not support a return on common
equity higher than 13.0% and remanded to the PSC a portion of its
July 1989 order for a determination of the proper return on
common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other non-
material adjustments to the calculation of cost-of-service. The
total refund, before interest and income taxes, was approximately
$14.6 million and was charged against 1992 "Electric Revenues."
The refund plus interest was made during 1993.

<PAGE>

G. On November 28, 1989 the PSC granted SCE&G an increase in
firm retail natural gas rates, effective November 30, 1989,
designed to increase annual revenues by $10.1 million, or 89.5%
out of the requested increase of approximately $11.3 million. In
its order the PSC authorized a 12.75% return on common equity.
The Consumer Advocate appealed to the Supreme Court which on
August 31, 1992 remanded the order to the PSC for redetermination
of the proper amount of litigation expenses to include in the
test period. In January 1993 the PSC reduced the amount of
litigation expense and ordered a refund totaling approximately
$163,000 which was charged against 1992 "Gas Revenues." The
refund was made during 1993.

3. LONG-TERM DEBT:

The annual amounts of long-term debt maturities, including
the amounts due under the nuclear and fossil fuel agreement (see
Note 4), and sinking fund requirements for the years 1994 through
1998 are summarized as follows:

Year Amount Year Amount
(Thousands of Dollars)

1994 $34,322 1997 $34,591
1995 94,067 1998 59,228
1996 69,269

Approximately $10.9 million of the current portion of long-
term debt for 1994 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.

During 1993 certain issues of SCE&G's First and Refunding
Mortgage Bonds were redeemed and replaced with SCE&G's First
Mortgage Bonds.

In January 1994 the Company arranged for unsecured bank
loans totaling $60 million, due January 13, 1995 at interest
rates between 3.875% and 3.89%. Proceeds from the loan were
used to repay a $60 million bank loan due January 14, 1994;
accordingly, such loan is included in long-term debt at December
31, 1993.

Substantially all utility plant and fuel inventories are
pledged as collateral in connection with long-term debt.

4. FUEL FINANCINGS:

Nuclear and fossil fuel inventories are financed through the
issuance of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1996. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $75 million that may
be outstanding at any time.

Commercial paper outstanding totaled $36.8 million and $55.7
million at December 31, 1993 and 1992 at weighted average
interest rates of 3.47% and 3.81%, respectively.

<PAGE>

5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not Subject to Purchase
or Sinking Funds):

The changes in "Common Stock," without par value, during 1993, 1992 and
1991 are summarized as follows:

Number Thousands
of Shares of Dollars
Balance December 31, 1990 40,882,176 $575,251
Repurchase of common stock (1,000,000) (37,425)
Acquisition of propane operations 902,311 33,769
Other (160) 2
Balance December 31, 1991 40,784,327 571,597
Issuance of common stock 3,126,304 127,406
Balance December 31, 1992 43,910,631 699,003
Issuance of common stock 2,708,826 127,662
Balance December 31, 1993 46,619,457 $826,665

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 may limit the payment of cash dividends
on its common stock. In addition, with respect to hydroelectric
projects, the Federal Power Act may require the appropriation of
a portion of the earnings therefrom. At December 31, 1993
approximately $10.6 million of retained earnings were restricted
as to payment of cash dividends on common stock.

Cash dividends on common stock were declared at an annual
rate per share of $2.74, $2.68 and $2.62 for 1993, 1992 and 1991,
respectively.

6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):

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.

At any time when dividends have not been paid in full or
declared and set apart for payment on all series of preferred
stock, SCE&G may not redeem any shares of preferred stock (unless
all shares of preferred stock then outstanding are redeemed) or
purchase or otherwise acquire for value any shares of preferred
stock except in accordance with an offer made to all holders of
preferred stock. SCE&G may not redeem any shares of preferred
stock (unless all shares of preferred stock then outstanding are
redeemed) or purchase or otherwise acquire for value any shares
of preferred stock (except out of monies set aside as purchase
funds or sinking funds for one or more series of preferred stock)
at any time when it is in default under the provisions of the
purchase fund or sinking fund for any series of preferred stock.

<PAGE>

The aggregate annual amounts of purchase fund or sinking fund
requirements for preferred stock for the years 1994 through 1998
are summarized as follows:

Year Amount Year Amount
(Thousands of Dollars)

1994 $2,504 1997 $2,440
1995 2,515 1998 2,440
1996 2,482

The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1993, 1992 and 1991 are summarized as follows:

Number Thousands
of Shares of Dollars
Balance December 31, 1990 1,050,201 $64,460
Shares Redeemed:
$100 par value (628) (63)
50 par value (51,169) (2,559)
Balance December 31, 1991 998,404 61,838
Shares Redeemed:
$100 par value (6,098) (610)
50 par value (51,777) (2,589)
Balance December 31, 1992 940,529 58,639
Shares Redeemed:
$100 par value (7,374) (737)
50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 $55,344

7. INCOME TAXES:

Total income tax expense for 1993, 1992 and 1991 is as follows:

1993 1992 1991
(Thousands of Dollars)
Current taxes:
Federal $59,590 $67,240 $43,485
State 6,409 8,146 5,284
Total current taxes 65,999 75,386 48,769
Deferred taxes, net:
Federal 23,219 (11,888) 25,548
State 6,003 413 4,653
Total deferred taxes 29,222 (11,475) 30,201
Investment tax credits:
Amortization of amounts deferred (credit) (3,659) (3,659) (3,645)

Total income tax expense $91,562 $60,252 $75,325

<PAGE>

Total income taxes differ from amounts computed by applying the statutory
Federal income tax rate of 35% for 1993 and 34% for 1992 and 1991
to pretax income as follows:

1993 1992 1991
(Thousands of Dollars)
Net income $167,981 $117,590 $135,851
Total income tax expense:
Charged to operating expenses 90,007 60,947 77,562
Charged (credited) to other income 1,555 (695) (2,237)
Preferred stock dividends 6,217 6,473 6,706
Total pretax income $265,760 $184,315 $217,882

Income taxes on above at statutory Federal
Federal income tax rate $ 93,016 $62,667 $74,080
Increases (decreases) attributable to:
Allowance for funds used during
construction (excluding nuclear fuel) (3,125) (1,868) (1,174)
Deferred return on plant investment,
net of amortization 1,486 1,444 1,444
Depreciation differences 2,794 2,129 1,613
Amortization of investment tax credits (3,659) (3,659) (3,645)
State income taxes (less Federal income
tax effect) 8,068 5,649 6,559
Deferred income tax flowback at higher
than statutory rates (4,411) (5,565) (3,226)
Alternate fuel production tax credit (1,373) (275) -
Other differences, net (1,234) (270) (326)
Total income tax expense $ 91,562 $60,252 $75,325

The Omnibus Budget Reconciliation Act was signed into law on
August 10, 1993, increasing the corporate tax rate from 34% to 35%
effective January 1, 1993. The impact of this change on the Company's
financial position and results of operations was not material.

The tax effects of significant temporary differences comprising the Company's
net deferred tax liability of $559.6 million at December 31, 1993
determined in accordance with Statement No. 109 (see Note 1I) are as
follows (thousands of dollars):

Deferred tax assets:
Unamortized investment tax credits $ 58,839
Cycle billing 15,084
Nuclear operations expenses 4,908
Deferred compensation 5,315
Uncollectible accounts 1,892
Other post retirement benefits 1,631
Injuries and damages 722
Other 8,488
Total deferred tax assets 96,879

Deferred tax liabilities:
Accelerated depreciation and amortization 604,091
Intangible drilling costs 15,768
Reacquired debt 7,574
Property taxes 6,406
Pension expense 6,266
Take-or-pay contracts 4,528
Nuclear system maintenance 2,965
Early retirement programs 1,961
Nuclear decontamination fund 1,417
Other 5,468
Total deferred tax liabilities 656,444
Net deferred tax liability $559,565

"Total deferred taxes" charged (credited) to income tax expense result
from timing differences in recognition of the following items:

1992 1991
(Thousands of Dollars)

Charged (credited) to expense:
Accelerated depreciation and
amortization $ 2,313 $23,900
Deferred fuel accounting (2,958) 461
Property taxes 562 1,692
Cycle billing (1,321) 3,608
Take-or-pay contracts (1,118) (1,099)
Intangible drilling costs 5,122 276
Nuclear refueling accrual (4,430) 2,052
Electric rate refund (6,571) -
Injuries and damages (1,377) -
Other, net (1,697) (689)
Total deferred taxes $(11,475) $30,201

The Internal Revenue Service has examined and closed consolidated Federal income
tax returns of the Company through 1989 and is currently examining the
1990 and 1991 Federal income tax returns. No adjustments are
currently proposed by the examining agent. The Company does not anticipate that
any adjustments which might result from this examination will have a
significant impact on the earnings or financial position of the Company.

8. FINANCIAL INSTRUMENTS:

The carrying amounts and estimated fair values of the Company's
financial instruments at December 31, 1993 and 1992 are as follows (thousands
of dollars):

1993 1992
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
Cash and temporary
cash investments $ 20,766 $ 20,766 $ 32,050 $ 32,050
Investments 5,312 15,235 5,066 10,195
Short-term borrowings 43,019 43,019 41,156 41,156
Total Long-Term Debt 1,458,721 1,551,873 1,229,458 1,272,922
Total Preferred Stock
(Subject to purchase
or sinking funds) 55,344 51,618 58,639 53,771
Gas futures contracts 137 650 338 260

The information presented herein is based on pertinent information available to the Company as of
December 31, 1993 and 1992. 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, 1993 and the current estimated fair value may differ significantly from the estimated fair value at
that date.

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

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

</TABLE>

<PAGE>

Fair values of investments and long-term debt are based on quoted market
prices for similar instruments, or for those instruments for which there
are no quoted market prices available, fair values are based on net present
value calculations. Investments which are not considered to be financial
instruments (goodwill) have been excluded from the carrying amount
and estimated fair value. Settlement of long-term debt may not be possible
or may not be a prudent management decision.

Short-term borrowings are valued at their carrying amount.

The fair value of preferred stock (subject to purchase or sinking funds)
and gas futures contracts is estimated on the basis of market prices.

Potential taxes and other expenses that would be incurred in an actual
sale or settlement have not been taken into consideration.

9. SHORT-TERM BORROWINGS:

The Company pays fees to banks as compensation for its lines of credit.
Commercial paper borrowings are for 270 days or less. Details of lines of
credit and short-term borrowings at December 31, 1993, 1992 and 1991
and for the years then ended are as follows:

1993 1992 1991
(Millions of Dollars)

Authorized lines of credit at year-end $175.0 $153.9 $141.7
Unused lines of credit at year-end $148.0 $127.8 $141.6

Short-term borrowings (including
commercial paper) during the year:
Maximum outstanding $304.8 $143.0 $134.0
Average outstanding $117.2 $ 75.3 $ 74.3
Weighted average daily interest rates:
Bank loans 3.57% 4.47% 6.32%
Commercial paper 3.13% 3.69% 6.31%

Short-term borrowings outstanding at
year-end:
Bank loans $ 42.0 $ 41.1 $ 20.7
Weighted average interest rate 3.71% 4.49% 5.89%
Commercial paper $ 1.0 - -
Weighted average interest rate 3.50% - -

10. COMMITMENTS AND CONTINGENCIES:

A. Construction

SCE&G entered into a contract with Duke/Fluor Daniel in 1991 to design,
engineer and build a 385 MW coal-fired electric generating plant near Cope,
South Carolina in Orangeburg County. Construction of the plant began in
November 1992 and commercial operation is expected in late 1995 or early
1996. The estimated price of the Cope plant, excluding financing costs
and AFC but including an allowance for escalation, is $450 million.
In addition, the transmission lines for interconnection with
the Company's system are expected to cost $26 million.

Under the Duke/Fluor Daniel contract SCE&G must make specified monthly
minimum payments. These minimum payments do not include amounts
for inflation on a portion of the contract which is subject to
escalation (approximately 34% of the total contract amount). The aggregate
amount of such required minimum payments remaining at December 31, 1993 is
as follows (thousands of dollars):

1994 $168,152
1995 59,766
1996 5,603

Total $233,521

Through December 31, 1993 SCE&G paid $142.0 million under the contract.

<PAGE>

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 $9.4 billion.
Each reactor licensee is currently liable for up to $79.3 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 $52.9 million per incident,
but not more than $6.7 million per year.

SCE&G currently maintains policies (for itself and on behalf of the PSA)
with Nuclear Electric Insurance Limited (NEIL) and American Nuclear Insurers
(ANI) providing combined property and decontamination insurance coverage of
$1.4 billion for any losses in excess of $500 million pursuant to existing
primary coverages (with ANI) on Summer Station. SCE&G pays annual premiums
and, in addition, could be assessed a retroactive premium not to exceed 7 1/2
times its annual premium in the event of property damages loss to any
nuclear generating facilities covered by NEIL. Based on the current annual
premium, this retroactive premium 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
materially adverse impact on the Company's financial position.

C. Litigation

In January 1994 SCE&G, acting on behalf of itself and the PSA (as
co-owners of Summer Station), reached a settlement with Westinghouse Electric
Corporation (Westinghouse) resolving a dispute involving steam generators
provided by Westinghouse to Summer Station which are defective in design,
workmanship and materials. Terms of the settlement are confidential.
SCE&G had filed an action in May 1990 against Westinghouse in the U.S. District
Court for South Carolina; an order dismissing this suit was issued on January
12, 1994.

D. Environmental

As described in Note 1L, the Company has an environmental assessment
program to identify and assess current and former operations sites
that could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures,
if any, necessary to investigate and clean up each site. These estimates
are refined as additional information becomes available; therefore actual
expenditures could significantly differ from the original estimates. Amounts
estimated and accrued to date for site assessments and cleanup relate
primarily to regulated operations; such amounts have been deferred
and are being amortized and recovered through rates over a ten-year period.

<PAGE>

11. SEGMENT OF BUSINESS INFORMATION:

Segment information at December 31, 1993, 1992 and 1991 and for the years
then ended is as follows:

1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,121 $320,195 $ 3,851 $1,264,167
Operating expenses,
excluding depreciation
and amortization 620,291 275,984 9,737 906,012
Depreciation and
amortization 97,849 14,820 175 112,844

Total operating expenses 718,140 290,804 9,912 1,018,856

Operating income (loss) $ 221,981 $ 29,391 $(6,061) 245,311

Add - Other income, net 30,076
Less - Interest charges 101,189
- Preferred stock dividends 6,217
Net income $ 167,981

Capital expenditures:
Identifiable $ 279,082 $ 28,761 $ 604 $ 308,447

Utilized for overall Company operations 13,934
Total $ 322,381

Identifiable assets at
December 31, 1993:
Utility plant, net $2,628,374 $312,437 $ 1,673 $2,942,484
Inventories 77,805 22,019 463 100,287
Total $2,706,179 $334,456 $ 2,136 3,042,771

Assets utilized for overall Company operations 997,755
Total assets $4,040,526

<PAGE>

1992
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 829,477 $305,275 $ 3,623 $1,138,375
Operating expenses,
excluding depreciation
and amortization 554,897 256,178 9,205 820,280
Depreciation and
amortization 93,978 14,174 163 108,315

Total operating expenses 648,875 270,352 9,368 928,595

Operating income (loss) $ 180,602 $ 34,923 $(5,745) 209,780

Add - Other income, net 11,883
Less - Interest charges 97,600
- Preferred stock dividends 6,473
Net income $ 117,590

Capital expenditures:
Identifiable $ 234,918 $ 33,495 $ 346 $ 268,759

Utilized for overall Company operations 8,877
Total $ 277,636

Identifiable assets at
December 31, 1992:
Utility plant, net $2,456,691 $299,591 $ 1,240 $2,757,522
Inventories 82,717 8,155 481 91,353
Total $2,539,408 $307,746 $ 1,721 2,848,875

Assets utilized for overall Company operations 708,846
Total assets $3,557,721

<PAGE>

1991
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 867,215 $ 276,742 $ 3,869 $1,147,826
Operating expenses,
excluding depreciation
and amortization 580,265 233,509 9,023 822,797
Depreciation and
amortization 88,803 13,720 146 102,669

Total operating expenses 669,068 247,229 9,169 925,466

Operating income (loss) $ 198,147 $ 29,513 $ (5,300) 222,360

Add - Other income, net 11,655
Less - Interest charges 91,458
- Preferred stock dividends 6,706
Net income $ 135,851

Capital expenditures:
Identifiable $ 205,704 $ 25,380 $ 89 $ 231,173

Utilized for overall Company operations 7,967
Total $ 239,140

Identifiable assets at
December 31, 1991:
Utility plant, net $2,333,877 $ 280,805 $ 1,073 $2,615,755
Inventories 83,637 7,242 476 91,355
Total $2,417,514 $ 288,047 $ 1,549 2,707,110

Assets utilized for overall Company operations 598,752
Total assets $3,305,862

12. QUARTERLY FINANCIAL DATA (UNAUDITED):

1993
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $321,840 $280,382 $359,453 $302,492 $1,264,167
Operating
income (000) 63,714 45,370 84,638 51,589 245,311
Net income (000) 45,110 26,909 64,427 31,535 167,981
Earnings per weighted
average share of
common stock
as reported 1.02 .61 1.41 .68 3.72

1992
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $297,414 $255,343 $305,594 $280,024 $1,138,375
Operating
income (000) 56,978 40,203 64,486 48,113 209,780
Net income (000) 34,132 16,753 39,643 27,062 117,590
Earnings per weighted
average share of
common stock
as reported .83 .41 .96 .64 2.84

64
<PAGE>
<PAGE>

<TABLE>

SCHEDULE V
SCANA CORPORATION
Property, Plant and Equipment
Year Ended December 31, 1993

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 2,526,525 $ 387,277 $ (58,121) $ 2,913,802
Production Plant - Steam 669,646,783 59,629,602 $23,804,759 705,413,505
Production Plant - Nuclear 901,572,157 6,351,974 2,080,492 905,843,639
Production Plant - Hydraulic 252,749,355 1,300,683 57,399 (16,026) 253,976,613
Other Production 63,281,062 866,307 1,500 (899,820) 63,246,049
Transmission 307,889,993 14,609,788 218,883 (642,210) 321,638,688
Distribution 909,829,946 71,365,534 6,417,737 622,432 975,400,175
General 95,416,815 7,591,100 4,188,810 726,828 99,545,933
Construction Work In Progress 214,684,529 109,652,365 324,336,894
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 3,418,534,056 271,754,630 36,769,580 (266,917) 3,653,252,189

Gas Utility Plant:
Intangible Plant 1,588,114 3,803 2,002 8,000 1,597,915
Production Plant 13,825,840 124,400 1,786,145 12,164,095
Storage Plant 18,995,679 24,066,291 43,061,970
Transmission 95,108,042 4,894,565 100,002,607
Distribution 251,015,851 12,446,005 244,443 263,217,413
General 31,050,085 1,452,363 990,665 (63,270) 31,448,513
Construction Work in Progress 23,879,649 (14,226,589) 9,653,060
Plant Acquisition Adjustment 37,141,178 37,141,178
Total Gas Plant 472,604,438 28,760,838 3,023,255 (55,270) 498,286,751

Transit Utility Plant:
Plant in Service 3,286,740 820,846 338,083 3,769,503
Construction Work In Progress 346,440 (217,070) 129,370
Total Transit Plant 3,633,180 603,776 338,083 3,898,873

Common Utility Plant:
Plant in Service 65,124,200 9,842,345 512,645 (1,650,001) 72,803,899
Construction Work in Progress 11,318,260 4,091,970 15,410,230
Total Common Plant 76,442,460 13,934,315 512,645 (1,650,001) 88,214,129

Nuclear Fuel, Net 39,916,340 7,325,982 (18,155,649) 29,086,673

Total Utility Plant 4,011,130,474 322,379,541 40,643,563 (20,127,837) 4,272,738,615

Nonutility Property 294,057,426 203,664,659 19,524,066 6,403 478,204,422

Total Property, Plant and
Equipment $4,305,187,900 $526,044,200 $60,167,629 $ (20,121,434) $4,750,943,037

(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.

<PAGE>

SCHEDULE V
<S> <C> <C> <S><C> <C> <S><C> <S><C> <C> <C> <S><C>
SCANA CORPORATION
Property, Plant and Equipment
Year Ended December 31, 1992

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,745,368 $ 668,802 $ 112,355 $ 2,526,525
Production Plant - Steam 643,043,210 40,841,919 $ 14,653,122 414,776 669,646,783
Production Plant - Nuclear 902,210,500 10,513,580 11,089,182 (62,741) 901,572,157
Production Plant - Hydraulic 252,263,540 729,289 11,087 (232,387) 252,749,355
Other Production 60,580,141 3,495,438 72,541 (721,976) 63,281,062
Transmission 284,885,248 23,378,760 345,830 (28,185) 307,889,993
Distribution 836,231,555 80,261,671 6,726,789 63,509 909,829,946
General 86,645,581 12,212,253 2,218,502 (1,222,517) 95,416,815
Construction Work In Progress 173,266,342 41,418,187 214,684,529
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 3,241,808,376 213,519,899 35,117,053 (1,677,166) 3,418,534,056

Gas Utility Plant:
Intangible Plant 1,257,968 330,146 1,588,114
Production Plant 13,189,114 677,519 (40,793) 13,825,840
Storage Plant 18,837,405 119,974 38,300 18,995,679
Transmission 90,424,973 4,683,069 95,108,042
Distribution 237,384,817 14,584,843 953,809 251,015,851
General 29,036,158 2,630,570 801,843 185,200 31,050,085
Construction Work in Progress 13,410,561 10,469,088 23,879,649
Plant Acquisition Adjustment 37,141,178 37,141,178
Total Gas Plant 440,682,174 33,495,209 1,755,652 182,707 472,604,438

Transit Utility Plant:
Plant in Service 3,626,110 25,203 364,573 3,286,740
Construction Work In Progress 25,422 321,018 346,440
Total Transit Plant 3,651,532 346,221 364,573 3,633,180

Common Utility Plant:
Plant in Service 59,209,415 6,427,058 564,596 52,323 65,124,200
Construction Work in Progress 8,868,396 2,449,864 11,318,260
Total Common Plant 68,077,811 8,876,922 564,596 52,323 76,442,460

Nuclear Fuel, Net 41,708,502 21,398,027 (23,190,189) 39,916,340

Total Utility Plant 3,795,928,395 277,636,278 37,801,874 (24,632,325) 4,011,130,474

Nonutility Property 198,200,804 110,227,608 5,629,140 (8,741,846) 294,057,426

Total Property, Plant and
Equipment $3,994,129,199 $387,863,886 $ 43,431,014 $(33,374,171) $4,305,187,900

(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.

<PAGE>

SCHEDULE V
<S> <C> <C> <C> <S><C> <S><C> <S><C> <C> <C>
SCANA CORPORATION
Property, Plant and Equipment
Year Ended December 31, 1991

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)
Electric Utility Plant:
Intangible Plant $ 1,498,215 $ 247,153 $ 1,745,368
Production Plant - Steam 608,032,028 36,472,013 $ 3,099,376 $ 1,638,545 643,043,210
Production Plant - Nuclear 892,803,058 11,400,155 1,990,340 (2,373) 902,210,500
Production Plant - Hydraulic 246,061,917 6,234,421 18,421 (14,377) 252,263,540
Other Production 24,719,968 36,664,254 151,891 (652,190) 60,580,141
Transmission 268,810,887 17,218,465 756,709 (387,395) 284,885,248
Distribution 767,262,239 75,701,545 6,388,466 (343,763) 836,231,555
General 78,793,632 10,608,300 2,751,716 (4,635) 86,645,581
Construction Work In Progress 178,806,439 (5,540,097) 173,266,342
Plant Acquisition Adjustment 936,891 936,891
Total Electric Plant 3,067,725,274 189,006,209 15,156,919 233,812 3,241,808,376

Gas Utility Plant:
Intangible Plant 1,250,262 7,706 1,257,968
Production Plant 13,707,848 132,278 651,012 13,189,114
Storage Plant 18,001,686 835,719 18,837,405
Transmission 87,196,703 3,345,552 117,282 90,424,973
Distribution 220,080,221 16,825,100 582,092 1,061,588 237,384,817
General 29,478,406 2,913,166 2,297,108 (1,058,306) 29,036,158
Construction Work in Progress 12,089,655 1,320,906 13,410,561
Plant Acquisition Adjustment 37,141,178 37,141,178
Total Gas Plant 418,945,959 25,380,427 3,647,494 3,282 440,682,174

Transit Utility Plant:
Plant in Service 3,834,731 109,676 318,297 3,626,110
Construction Work In Progress 45,951 (20,529) 25,422

Total Transit Plant 3,880,682 89,147 318,297 3,651,532

Common Utility Plant:
Plant in Service 53,402,648 7,485,224 463,637 (1,214,820) 59,209,415
Construction Work in Progress 5,522,233 3,346,163 8,868,396
Total Common Plant 58,924,881 10,831,387 463,637 (1,214,820) 68,077,811

Nuclear Fuel, Net 43,394,098 16,697,735 (18,383,331) 41,708,502

Total Utility Plant 3,592,870,894 242,004,905 19,586,347 (19,361,057) 3,795,928,395

Nonutility Property 154,328,719 49,430,865 3,758,158 (1,800,622) 198,200,804

Total Property, Plant and
Equipment $3,747,199,613 $291,435,770 $23,344,505 $ (21,161,679) $3,994,129,199

(*) Includes accounting reclassification of property and equipment between various utility plant and nonutility
plant classifications.

<PAGE>

SCHEDULE VI
<S> <C> <C> <S><C> <C> <S><C> <S><C> <C> <S><C>
SCANA CORPORATION
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1993

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)

Electric Utility Plant:
Intangible Plant $ 510,230 $ 215,400 $ 725,630
Production Plant - Steam 259,740,060 18,455,648 $26,303,096 251,892,612
Production Plant - Nuclear 258,546,891 27,136,078 4,336,461 281,346,508
Production Plant - Hydraulic 56,833,113 3,708,900 387,290 60,154,723
Other Production 20,965,067 1,992,545 48,970 22,908,642
Transmission 94,236,791 7,748,900 610,744 101,374,947
Distribution 274,166,096 29,477,600 7,264,838 296,378,858
General 35,824,269 6,112,419 3,690,790 38,245,898
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 1,001,759,408 94,847,490 42,642,189 1,053,964,709

Gas Utility Plant:
Intangible Plant 301,503 138,457 439,960
Production Plant 5,193,715 (207,747) 723,075 4,262,893
Storage Plant 12,117,817 705,832 12,823,649
Transmission 54,755,006 2,176,154 56,931,160
Distribution 82,984,187 8,985,387 353,335 91,616,239
General 9,683,858 1,612,342 494,489 10,801,711
Gas Plant Acquisition Adj. 7,977,791 997,039 8,974,830
Total Gas Plant 173,013,877 14,407,464 1,570,899 185,850,442

Transit Utility Plant 2,393,120 167,000 333,808 2,226,312

Common Utility Plant:
Common Plant 21,919,678 2,711,444 395,972 24,235,150
Intangible Plant 1,764,900 622,600 2,387,500
Total Common Plant 23,684,578 3,334,044 395,972 26,622,650

Total Utility Plant 1,200,850,983 112,755,998 44,942,868 1,268,664,113

Nonutility Property 57,484,833 45,179,825 1,267,901 176,130 101,572,887

Total Property, Plant and
Equipment $1,258,335,816 $157,935,823 $46,210,769 176,130 $1,370,237,000

(*) After deduction of net salvage.

68
<PAGE>
<PAGE>

SCHEDULE VI
<S> <C> <C> <S><C> <C> <S><C> <S><C> <C> <S><C>
SCANA CORPORATION
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1992

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)

Electric Utility Plant:
Intangible Plant $ 483,330 $ 26,900 $ 510,230
Production Plant - Steam 260,113,888 15,938,325 $16,312,153 259,740,060
Production Plant - Nuclear 244,349,995 26,159,978 11,963,082 258,546,891
Production Plant - Hydraulic 53,551,159 3,474,075 192,121 56,833,113
Other Production 18,442,317 2,636,400 113,650 20,965,067
Transmission 87,812,534 7,068,000 643,743 94,236,791
Distribution 251,465,003 28,531,200 5,830,107 274,166,096
General 32,484,258 5,140,301 1,800,290 35,824,269
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 949,639,375 88,975,179 36,855,146 1,001,759,408

Gas Utility Plant:
Intangible Plant 188,424 113,079 301,503
Production Plant 4,968,219 226,954 1,458 5,193,715
Storage Plant 11,428,054 689,763 12,117,817
Transmission 52,684,280 2,070,726 54,755,006
Distribution 74,813,415 9,170,397 999,625 82,984,187
General 8,814,090 1,419,916 550,148 9,683,858
Gas Plant Acquisition Adj. 6,980,752 997,039 7,977,791
Total Gas Plant 159,877,234 14,687,874 1,551,231 173,013,877

Transit Utility Plant 2,579,278 146,500 332,658 2,393,120

Common Utility Plant:
Common Plant 18,020,122 4,033,463 133,907 21,919,678
Intangible Plant 1,160,900 604,000 1,764,900
Total Common Plant 19,181,022 4,637,463 133,907 23,684,578

Total Utility Plant 1,131,276,909 108,447,016 38,872,942 1,200,850,983

Nonutility Property 39,065,264 18,379,646 (39,058) $ 865 57,484,833

Total Property, Plant and
Equipment $1,170,342,173 $126,826,662 $38,833,884 $ 865 $1,258,335,816

(*) After deduction of net salvage.

69
<PAGE>
<PAGE>

SCHEDULE VI
<S> <C> <C> <S><C> <C> <S><C> <S><C> <C> <S><C>
SCANA CORPORATION
Accumulated Depreciation and Amortization of Property, Plant and Equipment
Year Ended December 31, 1991

Col. A Col. B Col. C Col. D Col. E Col. F

Balance at Balance
beginning Other Changes at close
Classification of period Additions Retirements add (deduct) of period
(*)

Electric Utility Plant:
Intangible Plant $ 282,630 $ 200,700 $ 483,330
Production Plant - Steam 242,322,141 15,286,854 $(2,512,260) $ (7,367) 260,113,888
Production Plant - Nuclear 220,460,998 25,905,578 2,016,581 244,349,995
Production Plant - Hydraulic 50,787,917 3,478,800 715,558 53,551,159
Other Production 17,204,322 1,591,396 353,401 18,442,317
Transmission 82,003,719 6,616,800 807,985 87,812,534
Distribution 232,605,806 26,114,400 7,255,203 251,465,003
General 29,725,228 5,114,200 2,355,170 32,484,258
Electric Plant Acquisition Adj. 936,891 936,891
Total Electric Plant 876,329,652 84,308,728 10,991,638 (7,367) 949,639,375

Gas Utility Plant:
Intangible Plant 73,197 115,227 188,424
Production Plant 5,119,939 444,495 567,222 (28,993) 4,968,219
Storage Plant 10,752,371 675,683 11,428,054
Transmission 50,815,965 1,988,274 113,962 (5,997) 52,684,280
Distribution 67,334,482 8,338,800 859,867 74,813,415
General 8,653,424 1,680,070 1,519,404 8,814,090
Gas Plant Acquisition Adj. 5,983,713 997,039 6,980,752
Total Gas Plant 148,733,091 14,239,588 3,060,455 (34,990) 159,877,234

Transit Utility Plant 2,674,599 130,100 225,421 2,579,278

Common Utility Plant:
Common Utility Plant 14,793,032 3,723,000 495,910 18,020,122
Intangible Plant 577,700 583,200 1,160,900
Total Common Plant 15,370,732 4,306,200 495,910 19,181,022

Total Utility Plant 1,043,108,074 102,984,616 14,773,424 (42,357) 1,131,276,909

Nonutility Property 24,781,200 14,732,715 474,881 26,230 39,065,264

Total Property, Plant and
Equipment $1,067,889,274 $117,717,331 $15,248,305 $(16,127) $1,170,342,173

(*) After deduction of net salvage.

70
<PAGE>
<PAGE>

SCHEDULE X

<S> <C> <C> <C>
SCANA CORPORATION
Supplementary Income Statement Information
Years Ended December 31, 1993, 1992, 1991

Maintenance (including repairs) and provisions for depreciation and amortization of utility plant are shown
separately in the accompanying consolidated statements of income, except for amounts charged to clearing and
other accounts, which amounts are not significant. Advertising expenses and royalties are not material. Taxes
other than income taxes are as follows (amounts for nonutility operations are not significant):

Years Ended December 31,
1993 1992 1991
(Thousands of Dollars)

State electric generation tax $ 6,129 $ 5,680 $ 5,633
General property taxes 52,480 51,981 48,787
Special state utility license 1,941 2,102 1,710
Federal social security taxes 9,080 8,689 7,982
State gross receipts tax 3,406 3,729 3,295
Franchise licenses 95 341 89
Other taxes 495 518 974
Total charged to operating expenses $73,626 $73,040 $68,470

<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable

PART III

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 the Registrant" on page 26 herein. The
other information required by Item 10, as well as that called for
by Item 11, "Executive Compensation," Item 12, "Security
Ownership of Certain Beneficial Owners and Management" and Item
13, "Certain Relationships and Related Transactions" is
incorporated herein by reference to the captions "Election of
Directors - Proposal 1," "Security Ownership of Certain
Beneficial Owners and Management," "Compensation of Directors,"
Compensation Committee Interlocks and Insider Participation,"
"Executive Compensation," "Description of Plan," and "Compliance
with Section 16(a) of the Securities Exchange Act of 1934" in the
Company's 1994 definitive proxy statement which will be filed
with the SEC pursuant to Regulation 14A, promulgated under the
Securities Exchange Act of 1934.

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
of the Management Development and Corporate Performance Committee
and the Long-term Compensation Committee on Executive
Compensation and the Performance Graph included in the Company's
1994 Proxy Statement shall not be incorporated by reference into
any such filings.

<PAGE>

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K

(a) Documents filed as a part of this report:

1. Financial Statements and Schedules: See Table of Contents of
Consolidated Financial Statements and Supplementary Financial
Data on page 38.

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 SEC and which are designated by reference to their
exhibit numbers 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 reports for the Company's employee stock
purchase plan and employee stock ownership plan will be furnished
under cover of Form 10-K/A to the Commission when the information
becomes available.

For the purposes of complying with the amendments to the rules
governing Form S-8 (effective July 13, 1990) under the Securities
Act of 1933, the undersigned registrant hereby undertakes as
follows, which undertaking shall be incorporated by reference
into registrant's Registration Statements on Form S-8 Nos. 2-
92743 and 2-90618:

Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers
and controlling persons of the registrant pursuant to the
foregoing provisions, or otherwise, the registrant has been
advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of
any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question
whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final
adjudication of such issue.

As permitted under Item 601(b)(4)(iii), instruments defining the
rights of holders of long-term debt of less than $400,000,000, or
10 percent of the total consolidated assets of the Company and
its subsidiaries, have been omitted and the Company agrees to
furnish a copy of such instruments to the Commission upon
request.

Reports on Form 8-K

The Company filed a report on Form 8-K on January 13, 1994 in
response to Item 5, "Other Events" regarding SCE&G's settlement
with Westinghouse Electric Corporation of a lawsuit relating to
the steam generators provided to the Company's Summer Station.

<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.

(REGISTRANT) SCANA CORPORATION

BY (SIGNATURE) s/L. M. GRESSETTE, JR.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief
Executive Officer, President and Director
DATE February 15, 1994

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.

(i) Principal executive officer:
BY (SIGNATURE) s/L. M. GRESSETTE, JR.
(NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief
Executive Officer, President and Director
DATE February 15, 1994

(ii) Principal financial and accounting officer:
BY (SIGNATURE) s/W. B. TIMMERMAN
(NAME AND TITLE) W. B. Timmerman, Senior Vice President and Controller-
Chief Financial Officer and Director
DATE February 15, 1994

BY (SIGNATURE) s/B. L. AMICK
(NAME AND TITLE) B. L. Amick, Director
DATE February 15, 1994

BY (SIGNATURE) s/W. B. BOOKHART, JR.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 15, 1994

BY (SIGNATURE) s/W. T. CASSELS, JR.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 15, 1994
BY (SIGNATURE) s/H. M. CHAPMAN
(NAME AND TITLE) H. M. Chapman, Director
DATE February 15, 1994

BY (SIGNATURE) s/J. B. EDWARDS
(NAME AND TITLE) J. B. Edwards, Director
DATE February 15, 1994

<PAGE>

BY (SIGNATURE) s/E. T. FREEMAN
(NAME AND TITLE) E. T. Freeman, Director
DATE February 15, 1994

BY (SIGNATURE) s/B. A. HAGOOD
(NAME AND TITLE) B. A. Hagood, Director
DATE February 15, 1994

BY (SIGNATURE) s/W. Hayne HIPP
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 15, 1994

BY (SIGNATURE) s/B. D. KENYON
(NAME AND TITLE) B. D. Kenyon, Director
DATE February 15, 1994

BY (SIGNATURE) s/F. C. McMASTER
(NAME AND TITLE) F. C. McMaster, Director
DATE February 15, 1994

BY (SIGNATURE) s/HENRY PONDER
(NAME AND TITLE) Henry Ponder, Director
DATE February 15, 1994

BY (SIGNATURE) s/J. B. RHODES
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 15, 1994

BY (SIGNATURE) s/E. C. WALL, JR.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 15, 1994

BY (SIGNATURE) s/John A. WARREN
(NAME AND TITLE) John A. Warren, Director
DATE February 15, 1994

75
<PAGE>

</TABLE>

<PAGE>
SCANA CORPORATION
EXHIBIT INDEX
Sequentially
Numbered
Pages
Number

2. Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession

Plan of Exchange of South Carolina Electric &
Gas Company and SCANA Corporation (Exhibit 2 to
Registration Statement No. 2-93812)........................... #

3. Articles of Incorporation and By-Laws

A. Restated Articles of Incorporation of SCANA
Corporation as adopted on April 26, 1989
(Exhibit 3-A to Registration Statement No.
33-49145)................................................. #
B. Copy of By-Laws of SCANA Corporation as
amended on December 16, 1992 (Exhibit 3-B
to Registration Statement No. 33-49333)................... #

4. Instruments Defining the Rights of Security Holders,
Including Indentures

A. Articles of Exchange of South Carolina
Electric & Gas Company and SCANA Corporation
(Exhibit 4-A to Post-Effective Amendment No. 1
to Registration Statement No. 2-90438).................... #
B. Indenture dated as of November 1, 1989 to
The Bank of New York, Trustee (Exhibit 4-A
to Registration No. 33-32107)............................. #
C. Indenture dated as of January 1, 1945, from
the South Carolina Power Company (the "Power
Company") to 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
(Exhibit 2-B to Registration No. 2-26459)................. #
D. Fourth Supplemental Indenture dates as of
April 1, 1950, to Indenture referred to in
Exhibit 4C, pursuant to which the Company
assumed said Indenture (Exhibit 2-C to
Registration No. 2-26459)................................. #
E. Fifth through Fifty-first Supplemental
Indenture referred to in Exhibit 4C dated
as of the dates indicated below and filed
as exhibits to the Registration Statements
and 1934 Act reports whose file number are
set forth below........................................... #

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-Q to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363

# Incorporated herein by reference as indicated.

<PAGE>
SCANA CORPORATION
EXHIBIT INDEX
Sequentially
Numbered
Pages
Number

March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 4-C 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 4-C to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
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
F. Fifty-second Supplemental Indenture to Indenture
referred to in Exhibit 4-C dated as of July 1, 1993
(Filed as Exhibit 4-D to Form 10-Q for the
quarter ended June 30, 1993, File No. 1-3375)............. #
G. Indenture dated as of April 1, 1993 from
South Carolina Electric & Gas Company to
NationsBank of Georgia, National Association
(Filed as Exhibit 4-F to Registration Statement
No. 33-49421)............................................. #
H. First Supplemental Indenture to Indenture
referred to in Exhibit 4-G dated as of June 1, 1993
(Filed as Exhibit 4-G to Registration Statement
No. 33-49421)............................................. #
I. Second Supplemental Indenture to Indenture
referred to in Exhibit 4-G dated as of June 15, 1993
(Filed as Exhibit 4-G to Form 10-Q for the
quarter ended June 30, 1993, File No. 1-3375)............. #

9. Voting Trust Agreement
Not Applicable

10. Material Contracts

A. Copy of Voluntary Deferral Plan as amended through
October 26, 1988 (Exhibit 10-A to Form 10-K
for the year ended December 31, 1988 under cover of
Form SE, File No. 1-8809)................................. #

# Incorporated herein by reference as indicated.

<PAGE>
SCANA CORPORATION
EXHIBIT INDEX

Sequentially
Numbered
Pages

Number

B. Copy of Supplementary Voluntary Deferral Plan as
amended and restated through August 28, 1991
(Exhibit 10-B to Form 10-K for the year ended
December 31, 1991, under cover of Form SE,
File No. 1-8809).......................................... #
C. Copy of Key Executive Severance Benefit Plan as
adopted on February 28, 1990 (Exhibit 10-C to Form 10-K
for the year ended December 31, 1989 under cover of
Form SE, File No. 1-8809)................................. #
D. Copy of SCANA Corporation Performance Share Plan
as amended and restated effective February 16, 1993
(Exhibit 10-D to Form 10-K for the year ended
December 31, 1992, File No. 1-8809)....................... #
E. Form of Agreement under SCANA Corporation Key
Employee Retention Program (Exhibit 10-E to Form
10-K for the year ended December 31, 1991, under
cover of Form SE, File No. 1-8809)........................ #
F. Description of SCANA Corporation Whole Life Option
(Exhibit 10-F to Form 10-K for the year ended
December 31, 1991, under cover of Form SE, File
No. 1-8809)............................................... #
G. Description of SCANA Corporation Performance
Incentive Plan (Exhibit 10-G to Form 10-K for
the year ended December 31, 1991, under cover
of Form SE, File No. 1-8809).............................. #

11. Statement Re Computation of Per Share Earnings
Not Applicable

12. Statements Re Computation of Ratios (Filed herewith)......... 80

13. Annual Report to Security Holders, Form 10-Q or
Quarterly Report to Security Holders
Not Applicable

16. Letter Re Change in Certifying Accountant
Not Applicable

18. Letter Re Change in Accounting Principles
Not Applicable

19. Previously Unfiled Documents
Not Applicable

21. Subsidiaries of the Registrant
Included herein on Page 24

22. Published Report Regarding Matters Submitted to
Vote of Security Holders
Not Applicable

23. Consents of Experts and Counsel
Consent of Deloitte & Touche (Filed herewith)................ 83

24. Power of Attorney
Not Applicable

# Incorporated herein by reference as indicated.

<PAGE>
SCANA CORPORATION
EXHIBIT INDEX

Number

27. Financial Data Schedule
Not Applicable

28. Information from Reports Furnished to State
Insurance Regulatory Authorities
Not Applicable

99. Additional Exhibits
Not Applicable

# Incorporated herein by reference as indicated.

79
<PAGE>

<PAGE>

Exhibit 12

SCANA CORPORATION
CALCULATIONS OF BOND RATIO
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)

Net earnings(1) $316,061

Divide by annualized interest charges on:
Bonds authenticated under the Company's
First and Refunding Mortgage Bond
Indenture $84,714
Other indebtedness (1) $ 821
Total annualized interest charges $ 85,535

Bond Ratio 3.70

(1) As defined under SCE&G's First and Refunding Mortgage Bond
Indenture.

80
<PAGE>
<PAGE>

SCANA CORPORATION
CALCULATIONS OF PREFERRED STOCK RATIO
FOR THE YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)

Net Earnings (1) $231,190

Divide by annualized interest charges on:
Bonds authenticated under SCE&G's
mortgage bond indentures $84,714
Other indebtedness (1) $ 912
Preferred Dividend Requirements $ 6,156
Total annualized interest charges $ 91,782

Preferred stock ratio 2.52

(1) As defined under SCE&G's Restated Articles of Incorporation.

81
<PAGE>
<PAGE>

<TABLE>

SCANA CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
For Each of the Five Years Ended December 31, 1993
(Thousands of Dollars)

Years Ended December 31,

1993 1992 1991 1990 1989
Fixed Charges as defined:
Interest on long-term debt.................. $ 96,916 $ 92,178 $ 87,854 $ 84,563 $ 86,178
Amortization of debt premium, discount and
expense (net).............................. 1,779 874 835 681 711
Other interest expense...................... 8,672 8,819 7,649 10,552 7,533
Interest component of rentals............... 2,853 929 897 951 983

Total Fixed Charges (A)................. $110,220 $102,800 $ 97,235 $ 96,747 $ 95,405

Earnings, as defined:
Income...................................... $174,198 $124,063 $142,557 $188,514 $129,888
Income taxes................................ 91,562 60,252 75,325 108,202 54,322
Total fixed charges above................... 110,220 102,800 97,235 96,747 95,405

Total Earnings (B)...................... $375,980 $287,115 $315,117 $393,463 $279,615

Ratio of Earnings to fixed charges (B/A)...... 3.41 2.79 3.24 4.07 2.93

</TABLE>

82<PAGE>

<PAGE>

EXHIBIT 23

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Post-Effective
Amendment No. 4 to Registration Statement No. 2-92743 of SCANA
Corporation on Form S-8, Post-Effective Amendment No. 4 to
Registration Statement No. 2-90618 on Form S-8, Post-Effective
Amendment No. 1 to Registration Statement No. 33-32107 on Form S-3,
Registration Statement No. 33-44317 on Form S-8, Post-Effective
Amendment No. 1 to Registration Statement No. 33-43636 on Form S-3
and Registration Statement No. 33-49333 on Form S-8 of our report
dated February 7, 1994 appearing in this Annual Report on Form 10-K
of SCANA Corporation for the year ended December 31, 1993.

s/Deloitte & Touche
DELOITTE & TOUCHE
Columbia, South Carolina
March 9, 1994