FILED TO INCLUDE FINANCIAL DATA SCHEDULE.

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K/A

AMENDMENT NO. 210-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, 19941996

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 1-3375

SOUTH CAROLINA ELECTRIC & GAS COMPANY
(Exact name of registrant as specified in its charter)

SOUTH CAROLINA 57-0248695
(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 Section 12(b) of the Act:

Title of each class Name of each exchange on which registered

5% Cumulative Preferred Stock
par value $50 per share New York Stock Exchange

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

Title of Class

The Class is comprised of the following series of Cumulative
Preferred Stock, par value $50 per share or $100 per share, having a
periodic sinking fund:

9.40% Cumulative Preferred Stock 8.72% Cumulative Preferred Stock
par value $50 per share par value $50 per share

8.12% Cumulative Preferred Stock 7.70% Cumulative Preferred Stock
par value $100 per share par value $100 per share

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. [X]

State the aggregate market value of the voting stock held by
nonaffiliates 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.)

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 non-
affiliates of the registrant as of February 28, 1997 was zero.

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.

As of February 28, 1997 there were issued and outstanding
40,296,147 shares of the registrant's common stock, $4.50 par value, all
of which were held, beneficially and of record, by SCANA Corporation.

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).

NONE

TABLE OF CONTENTS

Page

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

PART I

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

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

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

Item 4. Submission of Matters to a Vote of
Security Holders ................................... 21

PART II

Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters..................... 21

Item 6. Selected Financial Data ............................. 22

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations ...... 23

Item 8. Financial Statements and Supplementary Data ......... 30

Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ................ 57

PART III

Item 10. Directors and Executive Officers of the
Registrant ......................................... 57

Item 11. Executive Compensation .............................. 61

Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 65

Item 13. Certain Relationships and Related Transactions ...... 66

PART IV

Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K ............................ 66

SIGNATURES ........................................................ 67

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..................... South Carolina Electric & Gas Company
Consumer Advocate........... Consumer Advocate of South Carolina
Dekatherm................... One Million BTUs
DHEC........................ South Carolina Department of Health and
Environmental Control
DOE......................... United States Department of Energy
EPA......................... United States Environmental Protection Agency
FERC........................ United States Federal Energy Regulatory
Commission
Fuel Company................ South Carolina Fuel Company, Inc., an
affiliate
GENCO....................... South Carolina Generating Company, Inc., an
affiliate
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
Pipeline Corporation........ South Carolina Pipeline Corporation, an
affiliate
PRP......................... Potentially Responsible Party
PSA......................... The South Carolina Public Service Authority
PSC......................... The Public Service Commission of South
Carolina
PUHCA....................... Public Utility Holding Company Act of 1935,
as amended
SCANA....................... SCANA Corporation and its subsidiaries
Southern Natural............ Southern Natural Gas Company
Summer Station.............. V. C. Summer Nuclear Station
Supreme Court............... South Carolina Supreme Court
Transco..................... Transcontinental Gas Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............ A. M. Williams Coal-Fired, Electric
Generating Station Owned by GENCO

PART I

ITEM 1. BUSINESS

THE COMPANY

ORGANIZATION

The Company, a wholly owned subsidiary of SCANA, is a South
Carolina corporation organized in 1924 and has its principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Company had 3,637
full-time, permanent employees as of December 31, 1996 as compared
to 3,721 full-time, permanent employees as of December 31, 1995.

SCANA, a South Carolina corporation, was organized in 1984 and
is a public utility holding company within the meaning of PUHCA but
is presently exempt from registration under such Act. SCANA holds
all of the issued and outstanding common stock of the Company.
(See Note 1A of Notes to Consolidated Financial Statements.)

INDUSTRY SEGMENTS

The Company 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. The Company also renders urban bus service in the
metropolitan area of Columbia, South Carolina. The Company'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.

The Company'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 30 of the 46 counties in
South Carolina and covers more than 20,000 square miles. The total
population of the counties representing the Company's combined
service area is approximately 2.4 million.

The predominant industries in the territories served by the
Company 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.

Information with respect to industry segments for the years
ended December 31, 1996, 1995 and 1994 is contained in Note 11 of
Notes to Consolidated Financial Statements and all such information
is incorporated herein by reference.

COMPETITION

The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulation.
Deregulation of electric wholesale and retail markets is creating
opportunities to compete for new and existing customers and
markets. As a result, profit margins and asset values of some
utilities could be adversely affected. Legislative initiatives at
the Federal and state levels are being considered and, if enacted,
could mandate market deregulation. The pace of deregulation, the
future prices of electricity, and the regulatory actions which may
be taken by the PSC and the FERC in response to the changing
environment cannot be predicted. However, recent FERC actions will
likely accelerate competition among electric utilities by providing
for wholesale transmission access. In April 1996 the FERC issued
Order 888, which addresses open access to transmission lines and
stranded cost recovery. Order 888 requires utilities under FERC
jurisdiction that own, control or operate transmission lines to
file nondiscriminatory open access tariffs that offer to others the
same transmission service they provide themselves. The FERC has
also permitted utilities to seek recovery of wholesale stranded
costs from departing customers by direct assignment. Approximately
five percent of the Company's electric revenues is under FERC
jurisdiction.

The Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company operates
Strategic Business Units. Maintaining a competitive cost structure
is of paramount importance in the utility's strategic plan. The
Company has undertaken a variety of initiatives, including
reductions in operation and maintenance costs and in staffing
levels. In January 1996 the PSC approved (as discussed under
"Capital Requirements and Financing Program") the accelerated
recovery of the Company's electric regulatory assets and the shift,
for ratemaking purposes, of depreciation reserves from transmission
and distribution assets to nuclear production assets. The FERC has
rejected the depreciation reserve transfer for rates subject to its
jurisdiction. In May 1996 the FERC approved the Company's
application establishing open access transmission tariffs and
requesting authorization to sell bulk power to wholesale customers
at market-based rates. Significant investments are being made in
customer and management information systems. Marketing of services
to commercial and industrial customers has been increased
significantly. The Company believes that these actions as well as
numerous others that have been and will be taken demonstrate its
ability and commitment to succeed in the new operating environment
to come.

Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment occur,
the Company may no longer be eligible to apply this accounting
treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of
deregulation cannot be determined at present, discontinuation of
the accounting treatment could have a material adverse effect on
the Company's results of operations in the period the write-off is
recorded. It is expected that cash flows and the financial
position of SCANA would not be materially affected by the
discontinuation of the accounting treatment. The Company reported
approximately $284 million and $51 million of regulatory assets and
liabilities, respectively, including amounts recorded for net
deferred income tax assets and liabilities of approximately $104
million and $49 million, respectively, on its balance sheet at
December 31, 1996.

CAPITAL REQUIREMENTS AND FINANCING PROGRAM

Capital Requirements

The cash requirements of the Company arise primarily from its
operational needs and its construction program. The ability of the
Company to replace existing plant investments, as well as to expand
to meet future demand for electricity and gas, will depend upon its
ability to attract the necessary financial capital on reasonable
terms.

The Company recovers the costs of providing services through
rates charged to customers. Rates for regulated services are
generally based on historical costs. As customer growth and
inflation occur and the Company continues its ongoing construction
program 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 its ability to obtain adequate and timely rate
and other regulatory relief. On January 9, 1996 the PSC issued an
order granting the Company an increase in retail electric rates of
7.34%, which will produce additional revenues of approximately
$67.5 million annually. The increase has been implemented in two
phases. The first phase, an increase in revenues of approximately
$59.5 million annually based on a test year, or 6.47%, commenced in
January 1996. The second phase, an increase in revenues of
approximately $8.0 million annually, based on a test year, or .87%,
was implemented in January 1997. The PSC authorized a return on
common equity of 12.0%. The PSC also approved establishment of a
Storm Damage Reserve Account capped at $50 million to be collected
through rates over a ten-year period. Additionally, the PSC
approved accelerated recovery of a significant portion of the
Company's electric regulatory assets (excluding deferred income tax
assets) and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods to
allow recovery by the end of the year 2000. The Company's request
to shift, for ratemaking purposes, approximately $257 million of
depreciation reserves from transmission and distribution assets to
nuclear production assets was also approved. The PSC's ruling does
not apply to wholesale electric revenues under the FERC's
jurisdiction, which constitute approximately five percent of the
Company's electric revenues. The FERC has rejected the transfer of
depreciation reserve for rates subject to its jurisdiction.

During 1997 the Company is expected to meet its capital
requirements principally through internally generated funds
(approximately 72%, after payment of dividends), the issuance and
sale of debt securities and additional equity contributions from
SCANA. 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 revised estimates of its cash requirements for
construction and nuclear fuel expenditures, which are subject to
continuing review and adjustment, for 1997 and the two-year period
1998-1999 as now scheduled, are as follows:

Type of Facilities 1998-1999 1997
(Thousands of Dollars)
Electric Plant:
Generation. . . . . . . . . . . . . . . . $127,397 $ 61,869
Transmission. . . . . . . . . . . . . . . 40,442 19,801
Distribution. . . . . . . . . . . . . . . 121,821 63,250
Other . . . . . . . . . . . . . . . . . . 18,667 18,344
Nuclear Fuel. . . . . . . . . . . . . . . . 24,257 30,706
Gas . . . . . . . . . . . . . . . . . . . . 35,792 21,327
Common. . . . . . . . . . . . . . . . . . . 14,161 39,666
Other . . . . . . . . . . . . . . . . . . . 701 559
Total . . . . . . . . . . . . . . $383,238 $255,522

The above estimates exclude AFC.

Actual expenditures for the years 1997 and 1998-1999 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.

During 1996 the Company expended approximately $17.2 million
as part of a program to extend the operating lives of certain non-
nuclear generating facilities. Additional improvements to be made
under the program during 1997, included in the table above, are
estimated to cost approximately $34.6 million.

The Company's revised cost estimates for its construction
program for the periods 1997 and 1998-1999, shown in the above
table, include costs of the projects described below.

Other

In addition to the Company's capital requirements for 1997
described in "Capital Requirements" above, approximately $45.2
million will be required for refunding and retiring outstanding
securities and obligations. For the years 1998-2001, the Company
has an aggregate of $293.9 million of long-term debt maturing
(including approximately $69.2 million for sinking fund
requirements, of which $68.7 million may be satisfied by deposit
and cancellation of bonds issued upon the basis of property
additions or bond retirement credits) and $9.8 million of purchase
or sinking fund requirements for preferred stock.

SCANA and Westvaco Corporation have formed a limited liability
company, Cogen South LLC, to build and operate a $170 million
cogeneration facility at Westvaco's Kraft Division Paper Mill in
North Charleston, South Carolina. The facility will provide
industrial process steam for the Westvaco paper mill and shaft
horsepower to enable the Company to generate up to 99 megawatts of
electricity. Construction financing is being provided to Cogen
South LLC by banks. In addition to the cogeneration LLC, Westvaco
has entered into a 20-year contract with the Company for all its
electricity requirements at the North Charleston mill at the
Company's standard industrial rate. Construction of the plant
began in September 1996 and it is expected to be operational in the
fall of 1998.

Financing Program

The Company'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 twelve consecutive months out
of the fifteen months prior to the month of issuance are at least
twice the annual interest requirements on all Class A Bonds to be
outstanding (Bond Ratio). For the year ended December 31, 1996 the
Bond Ratio was 4.37. The issuance of additional Class A Bonds also
is restricted to an additional principal amount equal to (i) 60% of
unfunded net property additions (which unfunded net property
additions totaled approximately $379 million at December 31, 1996),
(ii) retirements of Class A Bonds (which retirement credits totaled
$69.6 million at December 31, 1996), and (iii) cash on deposit with
the Trustee.

The Company has a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are issued under the New Mortgage on the basis
of a like principal amount of Class A Bonds issued under the Old
Mortgage which have been deposited with the Trustee of the
New Mortgage (of which $185 million were available for such
purpose at December 31, 1996), 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 twelve
consecutive months out of the eighteen 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, 1996 the New Bond Ratio was 5.90.

Without the consent of at least a majority of the total voting
power of the Company's preferred stock, the Company 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 the Company'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, the Company
must obtain the FERC authority to issue short-term debt. As
amended by SCE&G's request approved in 1997 the FERC has authorized
the Company to issue up to $250 million of unsecured promissory
notes or commercial paper with maturity dates of twelve months or
less, but not later than December 31, 1999. Commercial paper
outstanding at December 31, 1996 was $90.0 million.

The Company had $145 million authorized and unused lines of
credit at December 31, 1996. In addition, Fuel Company has a
credit agreement for a maximum of $125 million with the full
amount available at December 31, 1996. The credit agreement
supports the issuance of short-term commercial paper for the
financing of nuclear and fossil fuels and sulfur dioxide emission
allowances. (See "Fuel Financing Agreements.") Fuel Company
commercial paper outstanding at December 31, 1996 was $66.1
million.

The Company'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 twelve consecutive months immediately preceding the month
of issuance are at least one and one-half times the aggregate of
all interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1996 the
Preferred Stock Ratio was 2.80.

The ratios of earnings to fixed charges (SEC Method) were
3.80, 3.41, 3.46, 3.57 and 2.73 for the years ended December 31,
1996, 1995, 1994, 1993 and 1992, respectively.

During 1996 the Company received $48.7 million in equity
contributions from SCANA. These contributions represented proceeds
from the sale of common stock through SCANA's Investor Plus Plan
and Stock Purchase Savings Program which in 1996 raised $20.8
million and $27.9 million, respectively, in equity capital.
Effective February 1, 1997 SCANA announced the conversion of the
Investor Plus Plan from an original issue plan to a market purchase
plan.

The Company expects that it has or can obtain adequate sources
of financing to meet its projected cash requirements for the next
twelve months and for the foreseeable future.

Fuel Financing Agreements

The Company 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 fuels. To finance nuclear and
fossil fuels and sulfur dioxide emission allowances, Fuel Company
issues, from time to time, commercial paper which is supported, up
to $125 million, by an irrevocable revolving credit agreement which
expires July 31, 1998. Accordingly, the amounts outstanding have
been included in long-term debt. This commercial paper and amounts
outstanding under the revolving credit agreement, if any, are
guaranteed by the Company.

At December 31, 1996 commercial paper outstanding was
approximately $66.1 million at a weighted average interest rate
of 5.62%. (See Notes 1M and 4 of Notes to Consolidated Financial
Statements.)

ELECTRIC OPERATIONS

Electric Sales

In 1996 residential sales of electricity accounted for 43% of
electric sales revenues; commercial sales 30%; industrial sales
19%; sales for resale 4%; and all other 4%. KWH sales by
classification for the years ended December 31, 1996 and 1995 are
presented below:

Sales
KWH %
Classification 1996 1995 Change
(thousands)

Residential 5,939,703 5,726,815 3.72
Commercial 5,222,517 5,078,185 2.84
Industrial 5,320,515 5,210,368 2.11
Sale for resale 1,023,211 1,063,064 (3.75)
Other 505,793 506,806 (0.20)
Total Territorial 18,011,739 17,585,238 2.43
Interchange 895,016 195,591 357.60
Total 18,906,755 17,780,829 6.33

Sales for resale includes electricity furnished for resale to
three municipalities, two electric cooperatives and, for 1995, one
state electric agency. One municipality and one electric
cooperative have notified the Company of their intent to terminate
in the year 2000 their wholesale power contracts with the Company
and bid out their electric requirements. Interchange sales during
1996 includes sales to thirteen investor-owned utilities, one
electric cooperative and two federal/state electric agencies.
During 1995, interchange sales includes sales to four investor-
owned utilities, one electric cooperative and one state electric
agency.

During 1996 the Company recorded a net increase of 8,965
electric customers, increasing its total customers to 493,346.

The electric sales volume for territorial sales increased for
the year ended December 31, 1996 compared to the prior year as a
result of increased residential and commercial sales due primarily
to customer growth. The all-time peak demand of 3,698 MW was set
on July 23, 1996.

Interchange sales volume for 1996 increased as a result of
additional system capacity resulting from the startup of the Cope
plant in early 1996.

On August 8, 1995 the Company signed an agreement with the DOE
to lease the Savannah River Site's (SRS) power and steam generation
and transmission facilities. The agreement calls for SRS to
purchase all its electrical and a majority of its steam
requirements from the Company. The Company is leasing (with an
option to renew) the power plant for ten years and the electrical
transmission lines for 40 years, with an option to refurbish the
facilities or build a new system.

Electric Interconnections

The Company purchases all of the electric generation of
Williams Station, owned by GENCO, under a Unit Power Sales
Agreement which has been approved by the FERC. Williams Station
has a generating capacity of 560 MW.

The Company's transmission system is part of the
interconnected grid extending over a large part of the southern and
eastern portions of the nation. The Company, 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. This Council
provides for coordinated planning for reliability among bulk power
systems in the Southeast. The Company 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 and GENCO for the years
1994-1996.

1996 1995 1994
Nuclear:
Per million BTU $ .47 $ .48 $ .51
Coal:
Company:
Per ton $39.27 $40.01 $39.92
Per million BTU 1.55 1.57 1.57
GENCO:
Per ton $41.66 $42.21 $41.85
Per million BTU 1.62 1.63 1.63
Weighted Average Cost
of All Fuels:
Per million BTU $ 1.52 $ 1.26 $ 1.39

The fuel costs for 1994 shown above exclude the effects of a
PSC-approved offsetting of fuel costs through the application of
credits carried on the Company'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 for the Company's KWH generation (including
Williams Station) by each category of fuel for the years 1994-1996
and the estimates for 1997 and 1998.
Percent of Total KWH Generated
Estimated Actual
1998 1997 1996 1995 1994

Coal 69% 71% 74% 65% 76%
Nuclear 26 24 24 27 17
Hydro 5 5 5 5 6
Natural Gas & Oil - - - 3 1
100% 100% 100% 100% 100%

Coal is used at all five of the Company's major fossil fuel-
fired plants and GENCO's Williams Station. Unit train deliveries
are used at all of these plants. On December 31, 1996 the Company
had approximately a 37-day supply of coal in inventory and GENCO
had approximately a 30-day supply.

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 89.1% of estimated requirements for 1997
(approximately 5.4 million tons, including requirements of Williams
Station).

The supply of contract coal is purchased from six suppliers
located in eastern Kentucky and southwest Virginia. Contract
commitments, which expire at various times from 1997-2003,
approximate 4.4 million tons annually. Sulfur restrictions on the
contract coal range from .75% to 2%.

The Company believes that its operations are in substantial
compliance with all existing regulations relating to the discharge
of sulfur dioxide. The Company is unaware that any more stringent
sulfur content requirements for existing plants are contemplated at
the State level by DHEC. However, the Company will be required to
meet the more stringent Federal emissions standards established by
the Clean Air Act (see "Environmental Matters").

The Company has adequate supplies of uranium or enriched
uranium product under contract to manufacture nuclear fuel for
Summer Station through 2005. The following table summarizes all
contract commitments for the stages of nuclear fuel assemblies:
Remaining Expiration
Commitment Contractor Regions(1) Date

Uranium Energy Resources
of Australia 13 1997
Uranium Everest Minerals 13 1996
Conversion ConverDyn 13 1997
Enrichment USEC (2) 13-18 2005
Fabrication Westinghouse 13-21 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. 12 was
loaded in 1996 and Region no. 13 will be loaded in 1997.

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

The Company has on-site spent nuclear fuel storage capability
until at least 2009 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 Matters"
for information regarding the contract with the DOE for disposal of
spent fuel.)

Decommissioning

Decommissioning of Summer Station is presently scheduled to
commence when the operating license expires in the year 2022.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning costs is
referred to as COMReP (Cost of Money Reduction Plan). Under this
plan, funds collected through rates ($3.2 million in each of 1996
and 1995) are used to pay premiums on insurance policies on the
lives of certain Company personnel. The Company is the beneficiary
of these policies. Through these insurance contracts, the Company
is able to take advantage of income tax benefits and accrue
earnings on the fund on a tax-deferred basis at a rate higher than
can be achieved using more traditional funding approaches. Amounts
for decommissioning collected through electric rates, insurance
proceeds, and interest on proceeds less expenses are transferred by
the Company to an external trust fund in compliance with the
financial assurance requirements of the Nuclear Regulatory
Commission. Management intends for the fund, including earnings
thereon, to provide for all eventual decommissioning expenditures
on an after-tax basis. The trust's sources of decommissioning
funds under the COMReP program include investment components of
life insurance policy proceeds, return on investment and the cash
transfers from the Company described above. The Company records
its liability for decommissioning costs in deferred credits.

GAS OPERATIONS

Gas Sales

In 1996 residential sales accounted for 46% of gas sales
revenues; commercial sales 31%; industrial sales 23%. Dekatherm
sales by classification for the years ended December 31, 1996 and
1995 are presented below:

Sales
Dekatherms %
Classification 1996 1995 Change

Residential 14,108,058 12,333,769 14.4
Commercial 11,027,830 10,436,987 5.7
Industrial 13,909,258 13,467,687 3.3
Transportation gas 3,108,058 3,603,314 (13.7)
Total 42,153,204 39,841,757 5.8

During 1996 the Company recorded a net increase of 5,154 gas
customers, increasing its total customers to 248,496.

The Company purchases all of its natural gas from Pipeline
Corporation.

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

The deregulation of natural gas prices at the wellhead 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.

On November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated 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.
The impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation.

Gas Cost and Supply

Pipeline Corporation purchases natural gas under contracts
with producers and marketers on a short-term basis at current price
indices and on a long-term basis for reliability assurance at index
prices plus a gas inventory charge. The gas is brought to South
Carolina through transportation agreements with both Southern
Natural and Transco, which expire at various times from 1997 to
2003. The volume of gas which Pipeline Corporation is entitled to
transport under these contracts on a firm basis is shown below:

Maximum Daily
Supplier Contract Demand Capacity (MCF)

Southern Natural Firm Transportation 188,000
Transco Firm Transportation 29,300
Total 217,300

Under a contract with Pipeline Corporation, the Company's
maximum daily contract demand is 224,270 dekatherms. The contract
allows the Company to receive amounts in excess of this demand
based on availability.

The average cost per MCF of natural gas purchased from
Pipeline Corporation was approximately $4.30 in 1996 compared to
$3.77 in 1995.

To meet the requirements of the Company and its other high
priority natural gas customers during periods of maximum demand,
Pipeline Corporation supplements its supplies of natural gas from
two LNG plants. The LNG plants are capable of storing the lique-
fied equivalent of 1,900,000 MCF of natural gas, of which
approximately 1,746,830 MCF were in storage at December 31, 1996.
On peak days the LNG plants can regasify up to 150,000 MCF per day.
Additionally, Pipeline Corporation had contracted for 6,450,727 MCF
of natural gas storage space of which 6,294,474 MCF were in storage
on December 31, 1996.

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

Curtailment Plans

The FERC has established allocation priorities applicable to
firm and interruptible capacities on interstate pipeline companies
which require Southern Natural and Transco to allocate capacity to
Pipeline Corporation. The FERC allocation priorities are not
applicable to deliveries by the Company to its customers, which are
governed by a separate curtailment plan approved by the PSC.

REGULATION

General

The Company 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. The Company is subject to regulation 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. (See "Capital Requirements and Financing
Program").

In the opinion of the Company, it will be able to meet
successfully the challenges of the NEPA without any material
adverse impact on its results of operations, financial position or
business prospects.

The Company 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:

Project Capability (KW) License Expiration Date

Neal Shoals 5,000 2036
Stevens Creek 9,000 2025
Columbia 10,000 2000
Saluda 206,000 2007
Parr Shoals 14,000 2020
Fairfield Pumped Storage 512,000 2020

Pursuant to the provisions of the Federal Power Act, as
amended, an application for a new license for Neal Shoals was filed
with the FERC on December 30, 1991. No competing applications were
filed. The FERC issued a new 40-year license for the Neal Shoals
project on June 17, 1996.

The Company filed a notice of intent to file an application
for a new license for Columbia on June 29, 1995. The application
for the new license will be filed by June 30, 1998.

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 Federal government takes over a project
or the FERC issues a license to another applicant, the original
licensee is entitled to be paid its net investment in the project,
not to exceed fair value, plus severance damages.

In May 1996 the FERC approved the Company's application
establishing open access transmission tariffs and requesting
authorization to sell bulk power to wholesale customers at market-
based rates.

Nuclear Regulatory Commission

The Company 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. 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.

In 1996, the NRC completed the Systematic Assessment of
Licensee Performance (SALP) for Summer Station. The station was
assessed in four functional areas. The results of the assessment
identified superior performance in Plant Operations, Maintenance
and Engineering and good performance in Plant Support. Superior is
the highest assessment given by the NRC.

Summer Station has received a category one rating from the
Institute of Nuclear Power Operations (INPO) in the last four out
of five evaluations. The category one rating is the highest given
by INPO for a nuclear plant's overall operations.

National Energy Policy Act of 1992 and FERC Orders 636 and 888

The Company's regulated business operations were impacted by
the NEPA and FERC Orders No. 636 and 888. NEPA was designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was intended to deregulate the markets
for interstate sales of natural gas by requiring that pipelines
provide transportation services that are equal in quality for all
gas suppliers whether the customer purchases gas from the pipeline
or another supplier. In the opinion of the Company, it continues
to be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any material
adverse impact on the results of operations, cash flows, financial
position or business prospects.

RATE MATTERS

The following table presents a summary of significant rate
activity for the years 1992-1996 based on test years:

REQUESTED GRANTED

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

PSC
Electric
Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88%
Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84%

Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering of rate of return the Company was
seeking.

On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34% which will
produce additional revenues of approximately $67.5 million
annually. The increase has been implemented in two phases. The
first phase, an increase in revenues of approximately $59.5 million
annually based on a test year, or 6.47%, commenced in January 1996.
The second phase, an increase in revenues of approximately $8.0
million annually, based on a test year, or .87%, was implemented in
January 1997. The PSC authorized a return on common equity of
12.0%. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million to be collected through rates
over a ten-year period. Additionally, the PSC approved accelerated
recovery of a significant portion of the Company's electric
regulatory assets (excluding deferred income tax assets) and the
remaining transition obligation for postretirement benefits other
than pensions, changing the amortization periods to allow recovery
by the end of the year 2000. The Company's request to shift, for
ratemaking purposes, approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved. The PSC's ruling does not
apply to wholesale electric revenue under the FERC's jurisdiction,
which constitute approximately five percent of the Company's
electric revenues. The FERC has rejected the transfer of
depreciation reserves for rates subject to its jurisdiction.

In 1994 the PSC issued an order approving the Company's request
to recover through a billing surcharge to its gas customers the
costs of environmental cleanup at the sites of former manufactured
gas plants. The billing surcharge is subject to annual review and
provides for the recovery of substantially all actual and projected
site assessment and cleanup costs and environmental claims
settlements for the Company's gas operations that had previously
been deferred. In October 1996, as a result of the ongoing annual
review, the PSC approved the continued use of the billing
surcharge. The balance remaining to be recovered amounts to
approximately $38.0 million.

In September 1992 the PSC issued an order granting the Company
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 the Company's request to
reduce the number of routes and frequency of service. The new
rates were placed into effect in October 1992. The Company
appealed the PSC's order to the Circuit Court, which in May 1995
ordered the case back to the PSC for reconsideration of several
issues including the low income rider program, routing changes, and
the $.75 fare. The Supreme Court declined to review an appeal of
the Circuit Court decision and dismissed the case. The PSC and
other intervenors filed another Petition for Reconsideration, which
the Supreme Court denied. The PSC and other intervenors filed
another appeal to the Circuit Court which the Circuit Court denied
in an Order dated May 9, 1996. In this Order, the Circuit Court
upheld its previous Orders and remanded them back to the PSC.
During August, the PSC heard oral arguments on the Orders on remand
for the Circuit Court. On September 30, 1996, the PSC issued an
order affirming its previous orders and denied the Company's
request for reconsideration. The Company has appealed these two
PSC orders back to the Circuit Court where they are awaiting
action.

Fuel Cost Recovery Procedures

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

In the April 1996 annual review of the fuel cost component of
electric rates, the PSC decreased the rate from 13.48 mills per KWH
to 13.10 mills per KWH, a monthly decrease of $0.38 for an average
customer using 1,000 KWH a month.

The Company's gas rate schedules and contracts include
mechanisms which allow it to recover from its customers changes in
the actual cost of gas. The Company'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 1996 review the PSC decreased the base cost of
gas from 43.081 cents per therm to 42.800 cents per therm which
resulted in a monthly decrease of $0.28 (including applicable
taxes) based on an average of 100 therms per month on a residential
bill during the heating season. In November 1996, the Company
requested that the base cost of gas be increased to 51.260 cents
per therm as a result of unforseen increases in current and
projected natural gas costs. The PSC approved the Company's
request effective for bills rendered beginning in December 1996.
An average residential bill for 100 therms per month increased by
$8.50.

ENVIRONMENTAL MATTERS

General

Federal and state authorities have imposed environmental
regulations and standards requirements relating primarily to air
emissions, wastewater discharges and solid, toxic and hazardous
waste management. Developments in these areas may require that
equipment and facilities be modified, supplemented or replaced.
The ultimate effect of these regulations and standards upon
existing and proposed operations cannot be forecast.

Capital Expenditures

In the years 1994 through 1996, capital expenditures for
environmental control amounted to approximately $73.2 million. In
addition, approximately $12.2 million, $10.4 million and $8.8
million of environmental control expenditures were made during
1996, 1995 and 1994, respectively, which were included in "Other
operation" and "Maintenance" expenses. It is not possible to
estimate all future costs for environmental purposes but forecasts
for capitalized expenditures are $18.0 million for 1997 and $119.2
million for the four-year period 1998 through 2001. These
expenditures are included in the Company's construction program.

Air Quality Control

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 had a compliance date of January 1, 1995
and the second, January 1, 2000. The Company's facilities did not
require modifications to meet the requirements of Phase I. The
Company will most likely meet the Phase II requirements through the
burning of natural gas and/or lower sulfur coal in its generating
units and the purchase and use of sulfur dioxide emission
allowances. Low nitrogen oxide burners are being installed to
reduce nitrogen oxide emissions to the levels required by Phase II.
Air toxicity regulations for the electric generating industry are
likely to be promulgated around the year 2000.

The Company filed compliance plans related to Phase II
requirements with DHEC during 1995. The Company currently
estimates that air emissions control equipment will require
capital expenditures of $105 million over the 1997-2001 period to
retrofit existing facilities, with increased operation and
maintenance cost of approximately $1 million per year. To meet
compliance requirements through the year 2006, the Company
anticipates total capital expenditures of approximately $122
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 the Company's and GENCO's generating
units. Concurrent with renewal of these permits the permitting
agency has implemented a more rigorous control program. The
Company has been developing compliance plans to meet this program.
Amendments to the Clean Water Act proposed in Congress include
several provisions which, if passed, could prove costly to the
Company. These include limitations to mixing zones and the
implementation of technology-based standards.

Superfund Act and Environmental Assessment Program

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,
estimates are made of the cost, if any, to investigate and clean up
each site. These estimates are refined as additional information
becomes available; therefore, actual expenditures could differ
significantly from original estimates. Amounts estimated and
accrued to date for site assessments and cleanup and environmental
claims settlements relate primarily to regulated operations; such
amounts are deferred and are being amortized and recovered through
rates over a five-year period for electric operations and an
eight-year period for gas operations. Deferred amounts totaled
$41.4 million and $18.0 million at December 31, 1996 and 1995,
respectively. The deferral includes the costs estimated to be
associated with the matters discussed below.

In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area site in Charleston, South Carolina. This
site originally encompassed approximately eighteen acres and
included properties which were the locations for industrial
operations, including a wood preserving (creosote) plant and
one of the Company'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, 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 PRPs 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 investigation process to be compressed significantly. The
PRPs have negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study and
a corresponding Scope of Work. Field work began in
November 1993 and a draft Remedial Investigation Report was
submitted to the EPA in February 1995. The Company resolved
second and third round comments and submitted a Final Draft
Remedial Investigation Report in October 1996. Although the
Company is continuing to investigate cost-effective cleanup
methodologies, further work is pending EPA approval of the
Final Draft Remedial Investigation Report.

In October 1996 the City of Charleston and the Company settled
all environmental claims the City may have had against the
Company involving the Calhoun Park area for a payment of $26
million over four years by the Company to the City. The Company
is recovering the amount of the settlement, which does not
encompass site assessment and cleanup costs, through rates in
the same manner as other amounts accrued for site assessments
and cleanup. As part of the environmental settlement, the
Company has agreed to construct an 1,100 space parking garage
on the Calhoun Park site and to transfer the facility to the
City in exchange for a 20-year municipal bond backed by
revenues from the parking garage and a mortgage on the parking
garage. The total amount of the bond is not to exceed $16.9
million, the maximum expected project cost. The Company does
not expect the settlement to have a material impact on the
Company's results of operations, cash flows or financial
position.

The Company owns three other decommissioned manufactured gas
plant sites which contain residues of by-product chemicals.
The Company maintains an active review of the sites to monitor
the nature and extent of the residual contamination.

The Company is pursuing recovery of environmental liabilities
from appropriate pollution insurance carriers.

Solid Waste Control

The South Carolina Solid Waste Policy and Management Act of
1991 directed the DHEC to promulgate regulations for the disposal
of industrial solid waste. DHEC has proposed a regulation, which
if adopted as a final regulation in its present form, would
significantly increase the Company's costs of construction and
operation of existing and future ash management facilities.

Nuclear Fuel Disposal

The Nuclear Waste Policy Act of 1982 requires that the United
States government make available by 1998 a permanent repository
for high-level radioactive waste and spent nuclear fuel and
imposes a fee of 1.0 mil per KWH of net nuclear generation after
April 7, 1983. Payments, which began in 1983, are subject to change
and will extend through the operating life of Summer Station. The
Company 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. The Company has on-site
spent nuclear fuel storage capability until at least 2009 and
expects to be able to expand its storage capacity to accommodate
the spent nuclear fuel output for the life of the plant through rod
consolidation, dry cask storage or other technology as it becomes
available. The Act also imposes on utilities the primary
responsibility for storage of their spent nuclear fuel until the
repository is available.

OTHER MATTERS

With regard to the Company'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 Company'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.

ELECTRIC

The following table gives information with respect to the
Company's electric generating facilities.

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
Summer (2) Nuclear Parr, SC 1984 628,000
D-Area (3) Coal DOE Savannah
River Site, SC 1995 17,000
Cope (4) Coal Cope, SC 1996 385,000

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 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr 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 (6) 3,756,000

(1) Summer rating.
(2) Represents the Company's two-thirds portion of the Summer
Station.
(3) This plant is operated under lease from the DOE and is
dispatched to DOE's Savannah River Site steam needs. "Net
Generating Capability" for this plant is expected average
hourly output. The lease expires on October 1, 2005.
(4) Plant began commercial operation in January 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.
(6) Excludes Williams Station.

The Company owns 430 substations having an aggregate
transformer capacity of 21,078,351 KVA. The transmission system
consists of 3,142 miles of lines and the distribution system
consists of 15,840 pole miles of overhead lines and 3,331 trench
miles of underground lines.

GAS

Natural Gas

The Company's gas system consists of approximately 7,029 miles
of three-inch equivalent distribution pipelines and approximately
11,474 miles of distribution mains and related service facilities.

Propane

The Company 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. These
facilities can store the equivalent of 430,405 MCF of natural gas.

TRANSIT

The Company owns 54 motor coaches used in the operation of the
Columbia transit system. The Columbia system is comprised of
fifteen routes covering 177 miles.

Effective October 1, 1996, the Company transferred ownership
and operation of the Charleston transit system to the City of
Charleston. As part of the transfer, the Company conveyed ownership
to the City of the facilities, equipment and four motor coaches
used in the operation of the transit system. The City and the
Company also entered into an interim operating agreement, renewable
semiannually, whereby the Company will operate the system for the
City until a Regional Transit Authority is established. The
Company and the City have agreed upon a rate structure that is
designed to allow the Company to recover its costs of operating the
Charleston transit system. The Charleston system is comprised of
fourteen routes covering 110 miles.

ITEM 3. LEGAL PROCEEDINGS

For information regarding legal proceedings, see ITEM 1.,
"BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS -
Superfund Act and Environmental Assessment Program" 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

PART II

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

All of the Company's common stock is owned by SCANA and
therefore there is no market for such stock. During 1996 and 1995
the Company paid $132.9 million and $116.7 million, respectively,
in cash dividends to SCANA.

The Restated Articles of Incorporation of the Company and the
Indenture underlying its First and Refunding Mortgage Bonds contain
provisions that may limit the payment of cash dividends on 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, 1996 approximately $17.6
million of retained earnings were restricted as to payment of cash
dividends on common stock.

ITEM 6. SELECTED FINANCIAL DATA

For the Years Ended December 31, 1996 1995 1994 1993 1992
Statement of Income Data (Thousands of Dollars, except statistics)
Operating Revenues $1,344,597 $1,211,087 $1,181,274 $1,118,433 $ 994,381
Operating Income 285,525 255,854 230,418 219,319 182,267
Other Income 4,120 9,553 7,271 6,585 3,006
Net Income 190,482 169,185 152,043 145,968 102,163
Earnings Available for
Common Stock 185,049 163,498 146,088 139,751 95,689

Balance Sheet Data
Utility Plant, Net $3,196,897 $3,157,657 $2,998,132 $2,687,193 $2,503,201
Total Assets 3,958,802 3,802,433 3,587,091 3,189,939 2,890,953

Capitalization:
Common equity 1,413,462 1,315,072 1,133,432 1,051,334 963,741
Preferred stock (Not subject
to purchase or sinking
funds) 26,027 26,027 26,027 26,027 26,027
Preferred stock, Net (Subject to
purchase or sinking funds) 43,014 46,243 49,528 52,840 56,154
Long-term debt, Net 1,276,758 1,279,379 1,231,191 1,097,043 945,964
Total Capitalization $2,759,261 $2,666,721 $2,440,178 $2,227,244 $1,991,886

Other Statistics
Electric:
Customers (Year-End) 493,346 484,381 476,438 468,901 461,928
Territorial Sales (Million KWH) 18,012 17,585 16,840 16,889 15,801
Residential:
Average annual use per customer
(KWH) 14,149 13,859 13,048 14,077 13,037
Average annual rate per KWH $.0785 $.0747 $.0743 $.0707 $.0695
Gas:
Customers (Year-End) 248,496 243,342 238,433 221,278 218,582
Sales, excluding transportation
(Thousand Therms) 390,451 362,384 322,837 267,335 256,495
Residential:
Average annual use per customer
(Therms) 639 570 538 606 577
Average annual rate per therm $.74 $.82 $.84 $.76 $.74

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

COMPETITION

The Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company operates
Strategic Business Units. Maintaining a competitive cost structure
is of paramount importance in the utility's strategic plan. The
Company has undertaken a variety of initiatives, including
reductions in operation and maintenance costs and in staffing
levels. In January 1996 the PSC approved (as discussed under
"Liquidity and Capital Resources") the accelerated recovery of the
Company's electric regulatory assets and the shift, for ratemaking
purposes, of depreciation reserves from transmission and
distribution assets to nuclear production assets. The FERC has
rejected the depreciation reserve transfer for rates subject to its
jurisdiction. In May 1996 the FERC approved the Company's
application establishing open access transmission tariffs and
requesting authorization to sell bulk power to wholesale customers
at market-based rates. Significant investments are being made in
customer and management information systems. Marketing of services
to commercial and industrial customers has been increased
significantly. The Company believes that these actions as well as
numerous others that have been and will be taken demonstrate its
ability and commitment to succeed in the new operating environment
to come.

Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment occur,
the Company may no longer be eligible to apply this accounting
treatment and may be required to eliminate such regulatory assets
from its balance sheet. Although the potential effects of
deregulation cannot be determined at present, discontinuation of
the accounting treatment could have a material adverse effect on
the Company's results of operations in the period the write-off is
recorded. It is expected that cash flows and the financial
position of SCANA would not be materially affected by the
discontinuation of the accounting treatment. The Company reported
approximately $284 million and $51 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred
income tax assets and liabilities of approximately $104 million and
$49 million, respectively, on its balance sheet at December 31,
1996.

LIQUIDITY AND CAPITAL RESOURCES

The cash requirements of the Company arise primarily from its
operational needs and its construction program. The ability of the
Company to replace existing plant investment, as well as to expand
to meet future demand for electricity and gas, will depend upon its
ability to attract the necessary financial capital on reasonable
terms. The Company recovers the costs of providing services
through rates charged to customers. Rates for regulated services
are generally based on historical costs. As customer growth and
inflation occur and the Company continues its ongoing construction
program, 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 its ability to obtain adequate and timely rate
and other regulatory relief.

On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which will
produce additional revenues of approximately $67.5 million
annually. The increase has been implemented in two phases. The
first phase, an increase in revenues of approximately $59.5 million
annually based on a test year, or 6.47%, commenced in January 1996.
The second phase, an increase in revenues of approximately $8.0
million annually, based on a test year or .87%, was implemented in
January 1997. The PSC authorized a return on common equity of
12.0%. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million and collected through rates
over a ten-year period. Additionally, the PSC approved accelerated
recovery of a significant portion of the Company's electric
regulatory assets (excluding deferred income tax assets) and the
remaining transition obligation for postretirement benefits other
than pensions, changing the amortization periods to allow recovery
by the end of the year 2000. The Company's request to shift, for
ratemaking purposes, approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved. The PSC's ruling does not
apply to wholesale electric revenue under the FERC's jurisdiction,
which constitute approximately five percent of the Company's
electric revenues. The FERC has rejected the transfer of
depreciation reserve for rates subject to its jurisdiction.

The estimated primary cash requirements for 1997, excluding
requirements for fuel liabilities and short-term borrowings,
(including notes payable to affiliated companies), and the actual
primary cash requirements for 1996 are as follows:

1997 1996
(Thousands of Dollars)
Property additions and construction
expenditures, net of allowance for
funds used during construction $224,816 $218,179
Nuclear fuel expenditures 30,706 12,724
Maturing obligations, redemptions and
sinking and purchase fund requirements 27,901 27,888
Total $283,423 $258,791

Approximately 72% of total cash requirements (after payment of
dividends) was provided from internal sources in 1996 as compared
to 45% in 1995.

The Company has a bond indenture dated April 1, 1993 (New
Mortgage) covering substantially all of its electric properties
under which its future mortgage-backed debt (New Bonds) will be
issued. New Bonds are issued under the New Mortgage on the basis
of a like principal amount of Class A Bonds issued under the
Old Mortgage which have been deposited with the Trustee of
the New Mortgage (of which $185 million were available for such
purpose as of December 31, 1996), 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 twelve
consecutive months out of the eighteen 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, 1996 the New Bond Ratio was 5.90.

Pursuant to Section 204 of the Federal Power Act, the Company
must obtain the FERC authority to issue short-term indebtedness.
The FERC has authorized the Company to issue up to $250 million of
unsecured promissory notes or commercial paper with maturity
dates of twelve months or less, but not later than December 31,
1999.

The Company had $145 million authorized and unused lines of
credit at December 31, 1996. In addition, the Company has a
credit agreement for a maximum of $125 million with the full
amount available at December 31, 1996. The credit agreement
supports the issuance of short-term commercial paper for the
financing of nuclear and fossil fuels and sulfur dioxide emission
allowances. Fuel Company commercial paper outstanding at December
31, 1996 was $66.1 million.

The Company anticipates that its 1997 cash requirements of
$283.4 million will be met through internally generated funds
(approximately 72%, after payment of dividends), the sales of
additional equity securities, additional equity contributions from
SCANA 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 1997 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 for the next
twelve months and for the foreseeable future.

Environmental Matters

During 1995 the Company filed compliance plans related to
Phase II requirements with DHEC. The Company currently estimates
that air emissions control equipment will require capital
expenditures of $105 million over the 1997-2001 period to retrofit
existing facilities, with increased operation and maintenance cost
of approximately $1 million per year. To meet compliance
requirements through the year 2006, the Company anticipates total
capital expenditures of approximately $122 million.

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 the Company's and GENCO's generating
units. Concurrent with renewal of these permits, the permitting
agency has implemented a more rigorous control program. The
Company has been developing compliance plans for this program.
Amendments to the Clean Water Act proposed in Congress include
several provisions which, if passed, could prove costly to the
Company. These include limitations to mixing zones and the
implementation of technology-based standards.

The South Carolina Solid Waste Policy and Management Act of
1991 directed DHEC to promulgate regulations for the disposal of
industrial solid waste. DHEC has promulgated a proposed regulation
which, if adopted as a final regulation in its present form, would
significantly increase the Company's and GENCO's costs of
construction and operation of existing and future ash management
facilities.

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,
estimates are made of the cost, if any, to investigate and clean up
each site. These estimates are refined as additional information
becomes available; therefore, actual expenditures could differ
significantly from original estimates. Amounts estimated and
accrued to date for site assessments and cleanup and environmental
claims settlements relate primarily to regulated operations; such
amounts are deferred and are being amortized and recovered through
rates over a five-year period for electric operations and an
eight-year period for gas operations. Deferred amounts
totaled $41.4 million and $18.0 million at December 31, 1996 and
1995, respectively. The deferral includes the estimated costs
associated with the matters discussed below.

In September 1992 the EPA notified the Company, the City of
Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area site in Charleston, South Carolina. This
site originally encompassed approximately eighteen acres and
included properties which were the locations for industrial
operations, including a wood preserving (creosote) plant and
one of the Company'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 PRPs 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 investigation process to be compressed
significantly. The PRPs have negotiated an administrative
order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope
of Work. Field work began in November 1993 and a draft
Remedial Investigation Report was submitted to the EPA in
February 1995. The Company resolved second and third round
comments and submitted a Final Draft Remedial Investigation
Report in October 1996. Although the Company is continuing to
investigate cost-effective cleanup methodologies, further work
is pending EPA approval of the Final Draft Remedial
Investigation Report.

The Company is pursuing recovery of environmental liabilities
from appropriate pollution insurance carriers.
Regulatory Matters

The Company filed for electric rate relief in 1995 to
encompass primarily the remaining costs of completing the Cope
Generating Station. As discussed under "Liquidity and Capital
Resources," the PSC issued an order on January 9, 1996 increasing
electric retail rates.
The Company's regulated business operations were impacted by
the NEPA and FERC Orders No. 636 and 888. NEPA was designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. See "Competition" for a discussion of FERC
Order 888. Order No. 636 was intended to deregulate the markets
for interstate sales of natural gas by requiring that pipelines
provide transportation services that are equal in quality for all
gas suppliers whether the customer purchases gas from the pipeline
or another supplier. In the opinion of the Company, it continues
to be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any material
adverse impact on the results of operations, cash flows, financial
position or business prospects.

RESULTS OF OPERATIONS

Net Income

Net income and the percent increase (decrease) from the
previous year for the years 1996, 1995 and 1994 were as follows:

1996 1995 1994

Net income $190,482 $169,185 $152,043
Percent increase (decrease) in net
income 12.59% 11.27% 4.16%

1996 Net income increased for the year primarily as a result of
increases in electric and gas sales margins which more than
offset increases in operating expenses.

1995 Net income increased for the year primarily due to
increases in electric and gas sales margins and lower operating
and maintenance expenses which more than offset increases in
fixed costs.

The Company's financial statements include AFC. AFC is a
utility accounting practice whereby a portion of the cost of both
equity and borrowed funds used to finance construction (which is
shown on the balance sheet as construction work in progress) is
capitalized. An equity portion of AFC is included in nonoperating
income and a debt portion of AFC is included in interest charges
(credits) as noncash items, both of which have the effect of
increasing reported net income. AFC represented approximately 3.2%
of income before income taxes in 1996, 7.9% in 1995 and 6.3% in
1994.

Electric Operations

Electric sales margins for 1996, 1995 and 1994 were as
follows:

1996 1995 1994
(Millions of Dollars)

Electric revenues $1,106.7 $1,006.6 $974.3
(Provision) for rate refunds - - 1.2
Net Electric operating revenues 1,106.7 1,006.6 975.5
Less: Fuel used in electric generation 187.1 177.6 176.6
Purchased power 106.8 98.2 112.9
Margin $ 812.8 $ 730.8 $686.0

1996 The electric sales margin increased primarily over the prior
year primarily as a result of the rate increase received by the
Company in January 1996 and economic growth factors.

1995 The electric sales margin increased primarily as a result
of the combined impact of warmer weather in the third quarter of
1995, colder weather in the fourth quarter of 1995 and the base
rate increase received by the Company in mid-1994. These factors
more than offset the negative impact of milder weather experienced
during the first half of 1995.

Increases (decreases) from the prior year in megawatt hour
(MWH) sales volume by classes were as follows:

Classification 1996 1995

Residential 212,888 415,676
Commercial 144,332 229,565
Industrial 110,147 48,651
Sale for Resale (excluding interchange) (39,853) 38,688
Other (1,013) 12,776
Total territorial 426,501 745,356
Interchange 699,425 24,545
Total 1,125,926 769,901

Interchange sales volume for 1996 increased as a result of
additional capacity resulting from the startup of the Cope plant in
early 1996.

Gas Operations

Gas sales margins for 1996, 1995 and 1994 were as follows:

1996 1995 1994
(Millions of Dollars)

Gas operating revenues $234.8 $200.6 $201.7
Less: Gas purchased for resale 157.1 125.0 127.8
Margin $ 77.7 $ 75.6 $ 73.9

1996 The gas sales margin increased over the prior year as a
result of increased firm sales.

1995 The gas sales margin increased over the prior year
primarily as a result of increases in interruptible
gas sales.

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

Classification 1996 1995
Residential 1,774,289 802,211
Commercial 590,843 623,533
Industrial 441,571 2,528,974
Transportation gas (495,256) (1,866,414)
Total 2,311,447 2,088,304

Other Operating Expenses and Taxes

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

Classification 1996 1995
(Millions of Dollars)

Other operation and maintenance $22.3 $(7.8)
Depreciation and amortization 17.4 10.6
Income taxes 10.8 12.9
Other taxes 3.2 5.1
Total $53.7 $20.8

1996 Other operation and maintenance expenses increased primarily
as a result of higher production costs attributable
to the Cope plant which became operational in January 1996.
The increase in depreciation and amortization expenses
reflects the addition of the Cope plant and other additions
to plant-in-service. The increase in income tax expense
corresponds to the increase in operating income. The
increase in other taxes reflects higher property taxes
resulting from property additions and higher millages and
assessments.

1995 Other operation and maintenance expenses decreased primarily
as a result of lower pension costs and lower costs
at electric generating stations. The increase in
depreciation and amortization expense primarily is
attributable to additions to plant-in-service and the write
off of certain software costs. The increase in income tax
expense corresponds to the increase in operating income.
The increase in other taxes reflects higher property taxes
resulting from higher millages and assessments partially
offset by lower payroll taxes resulting from early
retirements of employees.

Interest Expense

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

Classification 1996 1995
(Millions of Dollars)

Interest on long-term debt, net $(1.2) $11.0
Other interest expense (2.0) 4.1
Total $(3.2) $15.1

1996 The decrease in interest expense is primarily a result of
reductions in outstanding debt throughout most of the
year.

1995 The increase in interest expense is due primarily to the
issuance of additional debt including commercial paper
during the latter part of 1994 and early 1995.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA

Page

Independent Auditors' Report....................................... 31

Consolidated Financial Statements:

Consolidated Balance Sheets as of December 31, 1996 and 1995... 33

Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1996, 1995 and 1994............. 34

Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994............................. 35

Consolidated Statements of Capitalization as of
December 31, 1996 and 1995................................... 36

Notes to Consolidated Financial Statements..................... 38

Supplemental financial statement schedules 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.

INDEPENDENT AUDITOR'S REPORT

South Carolina Electric & Gas Company:

We have audited the accompanying Consolidated Balance Sheets and
Statements of Capitalization of South Carolina Electric & Gas
Company (Company) as of December 31, 1996 and 1995 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,
1996. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion
on the financial statements 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, 1996 and 1995 and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally
accepted accounting principles.

s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 1997

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS

December 31, 1996 1995
(Thousands of Dollars)
ASSETS

Utility Plant (Notes 1, 3 and 4):
Electric $3,870,561 $3,277,530
Gas 338,095 320,847
Transit 3,923 3,768
Common 81,858 91,616
Total 4,294,437 3,693,761
Less accumulated depreciation and amortization 1,331,824 1,196,279
Total 2,962,613 2,497,482
Construction work in progress 193,278 613,683
Nuclear fuel, net of accumulated amortization 41,006 46,492
Utility Plant, Net 3,196,897 3,157,657

Nonutility Property and Investments, net of accumulated
depreciation (Note 8) 11,529 11,603

Current Assets:
Cash and temporary cash investments (Note 8) 5,399 6,798
Receivables - customer and other 170,476 154,816
Receivables - affiliated companies (Note 1) 1,021 7,132
Inventories (At average cost):
Fuel (Notes 1, 3 and 4) 33,121 35,812
Materials and supplies 45,375 43,583
Prepayments 8,758 10,158
Deferred income taxes 20,025 19,420
Total Current Assets 284,175 277,719

Deferred Debits:
Emission allowances 30,457 28,514
Environmental 41,375 18,016
Nuclear plant decommissioning fund (Note 1) 42,194 36,070
Pension asset, net (Note 1) 57,931 35,354
Other (Note 1) 294,244 237,500
Total Deferred Debits 466,201 355,454

Total $3,958,802 $3,802,433

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS

December 31, 1996 1995
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES

Stockholders' Investment:
Common equity (Note 5) $1,413,462 $1,315,072
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,439,489 1,341,099
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 43,014 46,243
Long-Term Debt, Net (Notes 3, 4 and 8) 1,276,758 1,279,379
Total Capitalization 2,759,261 2,666,721

Current Liabilities:
Short-term borrowings (Notes 8 and 9) 90,000 80,500
Current portion of long-term debt (Note 3) 42,755 36,033
Current portion of preferred stock (Note 6) 2,432 2,439
Accounts payable 66,741 71,731
Accounts payable - affiliated companies (Notes 1 and 3) 31,395 26,212
Customer deposits 14,944 12,518
Taxes accrued 66,900 64,008
Interest accrued 21,304 21,626
Dividends declared 35,972 33,126
Other 5,004 5,953
Total Current Liabilities 377,447 354,146

Deferred Credits:
Deferred income taxes (Notes 1 and 7) 521,745 488,310
Deferred investment tax credits (Notes 1 and 7) 75,073 78,316
Reserve for nuclear plant decommissioning (Note 1) 42,194 36,070
Other (Note 1) 183,082 178,870
Total Deferred Credits 822,094 781,566

Commitments and Contingencies (Note 10) - -

Total $3,958,802 $3,802,433

See Notes to Consolidated Financial Statements.

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

For the Years Ended December 31, 1996 1995 1994
(Thousands of Dollars)
Operating Revenues (Notes 1 and 2):
Electric $1,106,664 $1,006,566 $ 975,526
Gas 234,825 200,632 201,746
Transit 3,108 3,889 4,002
Total Operating Revenues 1,344,597 1,211,087 1,181,274

Operating Expenses:
Fuel used in electric generation 187,100 177,579 176,581
Purchased power (including affiliated
purchases)(Note 1) 106,792 98,231 112,900
Gas purchased from affiliate for resale (Note 1) 157,118 125,032 127,846
Other operation 222,361 211,318 214,344
Maintenance 64,369 53,071 57,801
Depreciation and amortization (Note 1) 134,951 117,584 106,952
Income taxes (Notes 1 and 7) 107,734 96,956 84,066
Other taxes (Note 12) 78,647 75,462 70,366
Total Operating Expenses 1,059,072 955,233 950,856

Operating Income 285,525 255,854 230,418

Other Income (Note 1):
Allowance for equity funds used during construction 4,055 9,499 7,989
Other income (loss), net of income taxes 65 54 (718)

Total Other Income 4,120 9,553 7,271

Income Before Interest Charges 289,645 265,407 237,689

Interest Charges (Credits):
Interest on long-term debt, net 97,149 98,361 87,361
Other interest expense (Notes 1 and 3) 7,367 9,324 5,189
Allowance for borrowed funds used
during construction (Note 1) (5,353) (11,463) (6,904)
Total Interest Charges, Net 99,163 96,222 85,646

Net Income 190,482 169,185 152,043

Preferred Stock Cash Dividends (At stated rates) (5,433) (5,687) (5,955)
Earnings Available for Common Stock 185,049 163,498 146,088
Retained Earnings at Beginning of Year 366,236 324,101 291,713
Common Stock Cash Dividends Declared (Note 5) (135,800) (121,363) (113,700)

Retained Earnings at End of Year $ 415,485 $ 366,236 $ 324,101

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 1996 1995 1994
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $190,482 $169,185 $152,043
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 135,070 117,839 107,103
Amortization of nuclear fuel 18,601 20,017 13,487
Deferred income taxes, net 32,098 (17,632) 13,133
Deferred investment tax credits, net (3,243) (3,230) (2,901)
Pension asset (22,577) (15,573) (8,452)
Allowance for funds used during construction (9,408) (20,962) (14,893)
Early retirements (1,890) (24,823) (7,086)
Nuclear refueling accrual (2,454) 6,957 (4,881)
Over (under) collections, fuel adjustment clause (8,261) 18,986 (17,965)
Emission allowances, net of AFC (1,885) (7,592) (19,409)
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (9,549) (16,148) (26,260)
(Increase) decrease in inventories 899 (4,857) 26
Increase (decrease) in accounts payable 193 3,120 (430)
Increase (decrease) in estimated rate
refunds and related interest - - (2,509)
Increase (decrease) in taxes accrued 2,892 17,362 6,681
Increase (decrease) in interest accrued (322) 92 3,770
Other, net (12,817) 11,185 20,444
Net Cash Provided From Operating Activities 307,829 253,926 211,901

Cash Flows From Investing Activities:
Utility property additions and
construction expenditures, net of AFC (230,603) (273,317) (406,054)
Nonutility property and investments (243) (111) (287)
Transfer of assets from SCANA - - 6,285
Net Cash Used For Investing Activities (230,846) (273,428) (400,056)

Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated company - - 19,409
Issuance of mortgage bonds - 99,583 99,207
Issuance of pollution control bonds - - 30,000
Equity contributions from parent 49,141 139,505 43,426
Other long-term debt 39,941 2,543 11,200
Repayments:
Notes payable - affiliated company - (19,409) -
Mortgage bonds (22,000) (64,779) -
Other long-term debt - (12,548) (1,662)
Preferred stock (3,236) (3,264) (3,398)
Redemption of Pollution Control Bonds (110) - -
Repayment of Bank Loans (2,542) - -
Dividend Payments:
Common stock (132,900) (116,663) (115,100)
Preferred stock (5,487) (5,750) (6,048)
Short-term borrowings, net 9,500 (19,500) 98,989
Fuel and emission allowance financings, net (10,689) 26,236 13,844
Advances - affiliated companies, net - - (1,559)
Net Cash Provided From Financing Activities (78,382) 25,954 188,308

Net Increase (Decrease) in Cash and Temporary Cash Investments (1,399) 6,452 153
Cash and Temporary Cash Investments, January 1 6,798 346 193
Cash and Temporary Cash Investments, December 31 $ 5,399 $ 6,798 $ 346
Supplemental Cash Flows Information:
Cash paid for - Interest (includes capitalized interest
of $5,353, $11,463 and $6,904) $102,609 $105,537 $ 87,255
- Income taxes 101,663 95,827 77,295
Noncash Financing Activities:
Charleston Franchise Agreement 21,429 - -
Charleston Environmental Agreement 19,500 - -

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31, 1996 1995
Common Equity (Note 5): (Thousands of Dollars)
Common stock, 4.50 par value, authorized 50,000,000 shares; issued
and outstanding, 40,296,147 shares $ 181,333 $ 181,333
Premium on common stock 395,072 395,072
Other paid-in capital 426,912 377,822
Capital stock expense (5,340) (5,391)
Retained earnings 415,485 366,236
Total Common Equity 1,413,462 51% 1,315,072 49%

Cumulative Preferred Stock (Not subject to purchase or sinking funds):

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

Shares Outstanding Redemption Price
Eventual
Series 1996 1995 Current Through Minimum
$100 Par 8.40% 197,668 197,668 101.00 - 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%

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 1996 1995 Current Through Minimum
7.70% 84,000 86,965 101.00 - 101.00 8,400 8,696
8.12% 118,812 123,045 102.03 - 102.03 11,881 12,305
Total 202,812 210,010

$50 Par Value - Authorized 1,602,539 shares

Shares Outstanding Redemption Price
Eventual
Series 1996 1995 Current Through Minimum
4.50% 16,000 17,519 51.00 - 51.00 800 876
4.60% 87 834 50.50 - 50.50 4 42
4.60%(A) 24,052 26,052 51.00 - 51.00 1,203 1,303
4.60%(B) 71,400 74,800 50.50 - 50.50 3,570 3,740
5.125% 71,000 72,000 51.00 - 51.00 3,550 3,600
6.00% 80,000 83,200 50.50 - 50.50 4,000 4,160
8.72% 64,000 95,985 51.00 12-31-98 50.00 3,200 4,799
9.40% 176,751 183,219 51.175 - 51.175 8,838 9,161
Total 503,290 553,609

$25 Par Value - Authorized 2,000,000 shares; None outstanding in 1996 and 1995

Total Preferred Stock (Subject to purchase or sinking funds) 45,446 48,682
Less: Current portion, including sinking fund requirements 2,432 2,439
Total Preferred Stock, Net (Subject to purchase or sinking funds) 43,014 2% 46,243 2%

See Notes to Consolidated Financial Statements.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31, 1996 1995
(Thousands of Dollars)
Long-Term Debt (Notes 3, 4 and 8):

First Mortgage Bonds:
Year of
Series Maturity

6% 2000 100,000 100,000
6 1/4% 2003 100,000 100,000
7.70% 2004 100,000 100,000
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
7 5/8% 2025 100,000 100,000

First and Refunding Mortgage Bonds:
Year of
Series Maturity

5.45% 1996 - 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 130,771 130,771
8 7/8% 2021 113,450 120,450

Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,450 6,560
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
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 30,000
Department of Energy Decontamination and Decommissioning Obligation 3,187 3,560
Commercial Paper 66,141 76,830
Charleston Franchise Agreement due 1997-2002 21,429 -
Charleston Environmental Agreement due 1997-1999 19,500 -
Other 25 3,993
Total Long-Term Debt 1,323,438 1,319,649
Less: Current maturities, including sinking fund requirements 42,755 36,033
Unamortized discount 3,925 4,237
Total Long-Term Debt, Net 1,276,758 46% 1,279,379 48%
Total Capitalization $2,759,261 100% $2,666,721 100%

See Notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

A. Organization and Principles of Consolidation

The Company, a public utility, is a South Carolina
corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation (SCANA), a South Carolina holding company. The
Company is engaged predominately in the generation and sale of
electricity to wholesale and retail customers in South Carolina
and in the purchase, sale and transportation of natural gas to
retail customers in South Carolina.

The accompanying Consolidated Financial Statements include
the accounts of the Company and South Carolina Fuel Company, Inc.
(Fuel Company). (See Note 1N.) Intercompany balances and
transactions between the Company and Fuel Company have been
eliminated in consolidation.

Affiliated Transactions

The Company has entered into agreements with certain
affiliates to purchase gas for resale to its distribution
customers and to purchase electric energy. The Company purchases
all of its natural gas requirements from Pipeline Corporation and
at December 31, 1996 and 1995 the Company had approximately $22.3
million and $17.5 million, respectively, payable to Pipeline
Corporation for such gas purchases. The Company purchases all of
the electric generation of Williams Station, which is owned by
GENCO, under a unit power sales agreement. At December 31, 1996
and 1995 the Company had approximately $8.6 million and $8.2
million, respectively, payable to GENCO for unit power purchases.
Such unit power purchases, which are included in "Purchased
power," amounted to approximately $95.3 million, $83.5 million
and $92.8 million in 1996, 1995 and 1994, respectively.

Total interest income, based on market interest rates,
associated with the Company's advances to affiliated companies
was approximately $36,000, $174,000 and $5,000 in 1996, 1995 and
1994, respectively.
In 1996 there were no amounts relating to advances from
affiliated companies included in "Other interest expense";
however, for 1995 and 1994 $114,000 and $279,000, respectively,
was included. Intercompany interest is calculated at market
rates.

B. Basis of Accounting

The Company accounts for its regulated utility operations,
assets and liabilities in accordance with the provisions of
Statements of Financial Accounting Standards No. 71 (SFAS 71).
The accounting standard requires cost-based rate-regulated
utilities, such as the Company, to recognize in their financial
statements revenues and expenses in different time periods than
do enterprises that are not rate-regulated. As a result the
Company has recorded, as of December 31, 1996, approximately
$284 million and $51 million of regulatory assets and
liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $104
million and $49 million, respectively. The electric regulatory
assets of approximately $119 million (excluding deferred income
tax assets) are being recovered through rates and, as discussed
in Note 2A, the Public Service Commission of South Carolina (PSC)
has approved accelerated recovery of approximately $64 million of
these assets. In the future, as a result of deregulation or
other changes in the regulatory environment, the Company may no
longer meet the criteria for continued application of SFAS 71 and
would be required to write off its regulatory assets and
liabilities. Such an event could have a material adverse effect
on the Company's results of operations in the period the write-
off is recorded, but it is not expected that cash flows or
financial position would be materially affected.

C. System of Accounts

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

D. Utility Plant

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

The Company, operator of the V. C. Summer Nuclear Station
(Summer Station), and the South Carolina Public Service Authority
(PSA) are joint owners of Summer Station in the proportions of
two-thirds and one-third, respectively. The parties share the
operating costs and energy output of the plant in these
proportions. Each party, however, provides its own financing.
Plant-in-service related to the Company's portion of Summer
Station was approximately $937.2 million and $925.1 million as of
December 31, 1996 and 1995, respectively. Accumulated
depreciation associated with the Company's share of Summer
Station was approximately $313.2 million and $261.0 million as of
December 31, 1996 and 1995, respectively. The Company's share of
the direct expenses associated with operating Summer Station is
included in "Other operation" and "Maintenance" expenses.

E. Allowance for Funds Used During Construction

AFC, a noncash item, reflects the period cost of capital
devoted to plant under construction. This accounting practice
results in the inclusion of, as a component of construction cost,
the costs of debt and equity capital dedicated to construction
investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates
for utility services. The Company has calculated AFC using
composite rates of 8.1%, 8.6% and 8.5% for 1996, 1995 and 1994,
respectively. These rates do not exceed the maximum allowable
rate as calculated under FERC Order No. 561. Interest on nuclear
fuel in process and sulfur dioxide emission allowances is
capitalized at the actual interest amount.

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 cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during semiannual fuel cost hearings. Any difference between
actual fuel costs and that contained in the fuel cost component
is deferred and included when determining the fuel cost component
during the next semiannual fuel cost hearing. The Company had
overcollected through the electric fuel cost component
approximately $1.9 million and $3.8 million at December 31, 1996
and December 31, 1995, 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, 1996 and 1995 the Company had
undercollected through the gas cost recovery procedure
approximately $10.9 million and $4.6 million, respectively, which
are included in "Deferred Debits - Other."

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

G. Depreciation and Amortization

Provisions for depreciation 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 3.13%, 3.02%
and 3.01% for 1996, 1995 and 1994, respectively.

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

H. Nuclear Decommissioning

Decommissioning of Summer Station is presently scheduled to
commence when the operating license expires in the year 2022.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning cost
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates ($3.2 million in each of
1996 and 1995) are used to pay premiums on insurance policies on
the lives of certain Company personnel. The Company is the
beneficiary of these policies. Through these insurance
contracts, the Company is able to take advantage of income tax
benefits and accrue earnings on the fund on a tax-deferred basis
at a rate higher than can be achieved using more traditional
funding approaches. Amounts for decommissioning collected
through electric rates, insurance proceeds, and interest on
proceeds less expenses are transferred by the Company to an
external trust fund in compliance with the financial assurance
requirements of the Nuclear Regulatory Commission. Management
intends for the fund, including earnings thereon, to provide for
all eventual decommissioning expenditures on an after-tax basis.
The trust's sources of decommissioning funds under the COMReP
program include investment components of life insurance policy
proceeds, return on investment and the cash transfers from the
Company described above. The Company records its liability for
decommissioning costs in deferred credits.

Pursuant to the National Energy Policy Act passed by
Congress in 1992 and the requirements of the DOE, the Company has
recorded a liability for its estimated share of the DOE's
decontamination and decommissioning obligation. The liability,
approximately $3.2 million at December 31, 1996, has been
included in "Long-Term Debt, Net." The Company is recovering the
cost associated with this liability through the fuel cost
component of its rates; accordingly, this amount has been
deferred and is included in "Deferred Debits - Other."

I. Income Taxes

The Company is included in the consolidated Federal income
tax return filed by SCANA. Income taxes are allocated to the
Company based on its contribution to the consolidated total.

Deferred tax assets and liabilities are recorded for the tax
effects of temporary differences between the book basis and tax
basis of assets and liabilities at currently enacted tax rates.
Deferred tax assets and liabilities are adjusted for changes in
such rates through charges or credits to regulatory assets or
liabilities if they are expected to be recovered from, or passed
through to, customers; otherwise, they are charged or credited to
income tax expense.

J. Pension Expense

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

Net periodic pension cost for the years ended December 31,
1996, 1995 and 1994 included the following components:

1996 1995 1994
(Thousands of Dollars)
Service cost--benefits earned during the period $ 6,511 $ 5,187 $ 8,684
Interest cost on projected benefit obligation 21,985 19,473 21,711
Adjustments:
Return on plan assets (78,614) (103,874) 2,365
Net amortization and deferral 40,150 74,769 (29,760)
Amounts contributed by the Company's
affiliates (335) (203) (130)
Net periodic pension (income) expense $(10,303) $ (4,648) $ 2,870

The determination of net periodic pension cost is based upon the
following assumptions:

1996 1995 1994
Annual discount rate 7.5% 8.0% 7.25%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 3.0% 2.5% 4.75%

The following table sets forth the funded status of the plan at December
31, 1996 and 1995:

1996 1995
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $243,872 $228,434
Nonvested benefit obligation 23,732 15,540
Accumulated benefit obligation $267,604 $243,974

Plan assets at fair value
(invested primarily in equity and debt securities) $523,530 $447,760
Projected benefit obligation 306,881 284,145
Plan assets greater than
projected benefit obligation 216,649 163,615
Unrecognized net transition liability 8,178 9,022
Unrecognized prior service costs 8,223 9,660
Unrecognized net gain (175,119) (146,943)
Pension asset recognized in
Consolidated Balance Sheets $ 57,931 $ 35,354

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 determining the amounts shown above for the years 1996 and
1995.

1996 1995

Annual discount rate used to determine
benefit obligations 7.5% 7.5%
Assumed annual rate of future salary increases
for projected benefit obligation 3.0% 3.0%

In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active and
retired employees. The costs of postretirement benefits other
than pensions are accrued during the years the employees render
the service necessary to be eligible for the applicable benefits.
Prior to 1993, the Company expensed these benefits, which are
primarily health care, as claims were incurred. In its June 1993
electric rate order the PSC approved the inclusion in rates of
the portion of increased expenses related to electric operations.
The Company expensed approximately $9.8 million, $8.5 million and
$8.6 million, net of payments to current retirees, for the years
ended December 31, 1996, 1995 and 1994, respectively.
Additionally, in 1996 the Company expensed approximately $6.2
million to accelerate the amortization of the remaining
transition obligation for postretirement benefits other than
pensions, as authorized by the PSC. (See Note 2A.)

Net periodic postretirement benefit cost for the years ended
December 31, 1996, 1995 and 1994, included the following
components:

1996 1995 1994
(Thousands of Dollars)

Service cost--benefits earned during the period $ 2,631 $ 2,076 $ 2,417
Interest cost on accumulated postretirement
benefit obligation 7,841 7,253 6,644
Adjustments:
Return on plan assets - - -
Amortization of unrecognized
transition obligation 9,513 3,344 3,344
Other net amortization and deferral 1,150 661 860
Amounts contributed by the Company's affiliates (711) (610) (575)
Net periodic postretirement benefit cost $20,424 $12,724 $12,690

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

1996 1995 1994

Annual discount rate 7.5% 8.0% 7.25%
Health care cost trend rate 9.5% 11.0% 11.25%
Ultimate health care cost trend rate (to be
achieved in 2004) 5.5% 6.0% 5.25%

The following table sets forth the funded status of the plan at December
31, 1996 and 1995:

1996 1995
(Thousands of Dollars)

Accumulated postretirement benefit obligations for:
Retirees $ 74,181 $ 64,989
Other fully eligible participants 6,674 6,685
Other active participants 29,275 27,076
Accumulated postretirement benefit obligation 110,130 98,750

Plan assets at fair value - -
Accumulated postretirement benefit obligation 110,130 98,750
Plan assets less than accumulated postretirement
benefit obligation (110,130) (98,750)
Unrecognized net transition liability 48,724 58,237
Unrecognized prior service costs 6,224 5,320
Unrecognized net loss 17,838 13,840
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(37,344) $(21,353)

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

1996 1995
Assumed health care cost trend rate used to
measure expected costs 9.5% 10.5%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.5% 5.5%
Annual discount rate 7.5% 7.5%
Annual rate of salary increases 3.0% 3.0%

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,
1996 and the accumulated postretirement benefit obligation as of
December 31, 1996 would be to increase such amounts by $191,000
and $3.2 million, respectively.

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 operating 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 differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup and
environmental claims settlements relate primarily to regulated
operations; such amounts are deferred and are being amortized and
recovered through rates over a five-year period for electric
operations and an eight-year period for gas operations. Such
deferred amounts totaled $41.4 million and $18.0 million at
December 31, 1996 and 1995, respectively. The deferral includes
the costs estimated to be associated with the matters discussed
in Note 10C.

M. Fuel Inventories

Nuclear fuel and fossil fuel inventories and sulfur dioxide
emission allowances are purchased and financed by Fuel Company
under a contract which requires the Company to reimburse Fuel
Company for all costs and expenses relating to the ownership and
financing of fuel inventories and sulfur dioxide emission
allowances. Accordingly, such fuel inventories and emission
allowances and fuel-related assets and liabilities are included
in the Company's consolidated financial statements. (See Note 4.)

N. 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.

O. Reclassifications

Certain amounts from prior periods have been reclassified to
conform with the 1996 presentation.

P. Use of Estimates

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

2. RATE MATTERS:

A. On January 9, 1996 the PSC issued an order granting the
Company an increase in retail electric rates of 7.34%, which will
produce additional revenues of approximately $67.5 million
annually. The increase has been implemented in two phases. The
first phase, an increase in revenues of approximately $59.5
million annually based on a test year, or 6.47%, commenced in
January 1996. The second phase, an increase in revenues of
approximately $8.0 million annually, based on a test year, or
.87%, was implemented in January 1997. The PSC authorized a
return on common equity of 12.0%. The PSC also approved
establishment of a Storm Damage Reserve Account capped at $50
million to be collected through rates over a ten-year period.
Additionally, the PSC approved accelerated recovery of a
significant portion of the Company's electric regulatory assets
(excluding deferred income tax assets) and the remaining
transition obligation for postretirement benefits other than
pensions, changing the amortization periods to allow recovery by
the end of the year 2000. The Company's request to shift, for
ratemaking purposes, approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved. The PSC's ruling does not
apply to wholesale electric revenues under the FERC's
jurisdiction, which constitute approximately five percent of the
Company's electric revenues. The FERC has rejected the transfer
of depreciation reserves for rates subject to its jurisdiction.

B. In 1994 the PSC issued an order approving the Company's
request to recover through a billing surcharge to its gas
customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge is subject
to annual review and provides for the recovery of substantially
all actual and projected site assessment and cleanup costs and
environmental claims settlements for the Company's gas operations
that had previously been deferred. In October 1996, as a result
of the ongoing annual review, the PSC approved the continued use
of the billing surcharge. The balance remaining to be recovered
amounts to approximately $38.0 million.

C. In September 1992 the PSC issued an order granting the
Company 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 the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect in October 1992.
The Company appealed the PSC's order to the Circuit Court, which
in May 1995 ordered the case back to the PSC for reconsideration
of several issues including the low income rider program, routing
changes, and the $.75 fare. The Supreme Court declined to review
an appeal of the Circuit Court decision and dismissed the case.
The PSC and other intervenors filed another Petition for
Reconsideration, which the Supreme Court denied. The PSC and
other intervenors filed another appeal to the Circuit Court which
the Circuit Court denied in an Order dated May 9, 1996. In this
Order, the Circuit Court upheld its previous Orders and remanded
them back to the PSC. During August, the PSC heard oral
arguments on the Orders on remand for the Circuit Court. On
September 30, 1996, the PSC issued an order affirming its
previous orders and denied the Company's request for
reconsideration. The Company has appealed these two PSC orders
back to the Circuit Court where they are awaiting action.

3. LONG-TERM DEBT:

The annual amounts of long-term debt maturities, including
amounts due under nuclear and fossil fuel agreements (see Note
4), and sinking fund requirements for the years 1997 through 2001
are summarized as follows:

Year Amount Year Amount
(Thousands of Dollars)

1997 $ 42,755 2000 $ 121,250
1998 113,876 2001 21,255
1999 27,746

Approximately $17.3 million of the portion of long-term debt
payable in 1997 may be satisfied by either deposit and
cancellation of bonds issued upon the basis of property additions
or bond retirement credits, or by deposit of cash with the
Trustee.

On August 7, 1996 the City of Charleston executed 30-year
electric and gas franchise agreements with the Company. In
consideration for the electric franchise agreement, the Company
will pay the City $25 million over seven years (1996-2002) and
has donated to the City the existing transit assets in
Charleston. The $25 million is included in electric plant-in-
service. In settlement of environmental claims the City may have
had against the Company involving the Calhoun Park area, where
the Company and its predecessor companies operated a manufactured
gas plant until the 1960's, the Company will pay the City $26
million over a four-year period (1996-1999). Such amount is
deferred (see Note 1L). Accordingly, the unpaid balances of
these amounts are included in "Long-Term Debt."

The Company has three-year revolving lines of credit
totaling $100 million, in addition to other lines of credit, that
provide liquidity for issuance of commercial paper. The three-
year lines of credit provide back-up liquidity when commercial
paper outstanding is in excess of $100 million. The long-term
nature of the lines of credit allow commercial paper in excess of
$100 million to be classified as long-term debt. SCE&G had
outstanding commercial paper of $90 million at December 31, 1996.

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 and sulfur dioxide
emission allowances are financed through the issuance by Fuel
Company of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1998. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $125 million that may
be outstanding at any time.

Commercial paper outstanding totaled $66.1 million and $76.8
million at December 31, 1996 and 1995 at weighted average
interest rates of 5.62% and 5.76%, respectively.

5. COMMON EQUITY:

The changes in "Stockholders' Investment" (Including
Preferred Stock Not Subject to Purchase or Sinking Funds) during
1996, 1995 and 1994 are summarized as follows:

Common Preferred Thousands
Shares Shares of Dollars

Balance December 31, 1993 40,296,147 322,877 $1,077,361
Changes in Retained Earnings:
Net Income 152,043
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,955)
Common Stock (113,700)
Equity Contributions from Parent 49,710
Balance December 31, 1994 40,296,147 322,877 1,159,459
Changes in Retained Earnings:
Net Income 169,185
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,687)
Common Stock (121,363)
Equity Contributions from Parent
including transfer of assets 139,505
Balance December 31, 1995 40,296,147 322,877 1,341,099
Changes in Retained Earnings:
Net Income 190,482
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,433)
Common Stock (135,800)
Equity Contributions from Parent 49,141
Balance December 31, 1996 40,296,147 322,877 $1,439,489

The Restated Articles of Incorporation of the Company and
the Indenture underlying its First and Refunding Mortgage Bonds
contain provisions that under certain circumstances could limit
the payment of cash dividends on common stock. In addition, with
respect to hydroelectric projects, the Federal Power Act requires
the appropriation of a portion of the earnings therefrom. At
December 31, 1996 approximately $17.6 million of retained
earnings were restricted by this requirement as to payment of
cash dividends on common stock.
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.

The aggregate annual amounts of purchase fund or sinking
fund requirements for preferred stock for the years 1997 through
2001 are summarized as follows:

Year Amount Year Amount
(Thousands of Dollars)

1997 $2,432 2000 $2,440
1998 2,440 2001 2,440
1999 2,440

The changes in "Total Preferred Stock (Subject to Purchase
or Sinking Funds)" during 1996, 1995 and 1994 are summarized as
follows:

Number Thousands
of Shares of Dollars

Balance December 31, 1993 881,968 $ 55,344
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 51,946
Shares Redeemed:
$100 par value (6,809) (681)
$50 par value (51,666) (2,583)
Balance December 31, 1995 763,619 48,682
Shares Redeemed:
$100 par value (7,198) (720)
$50 par value (50,319) (2,516)
Balance December 31, 1996 706,102 $ 45,446

7. INCOME TAXES:

Total income tax expense for 1996, 1995 and 1994 is as follows:

1996 1995 1994
(Thousands of Dollars)
Current taxes:
Federal $ 88,199 $94,137 $66,597
State 13,122 14,265 9,505
Total current taxes 101,321 108,402 76,102
Deferred taxes, net:
Federal 8,322 (7,319) 7,727
State 1,776 (603) 2,118
Total deferred taxes 10,098 (7,922) 9,845
Investment tax credits:
Amortization of amounts
deferred (credit) (3,243) (3,230) (3,231)
Total income tax expense $108,176 $97,250 $82,716

The difference in total income tax expense and the amount
calculated from the application of the statutory Federal income
tax rate (35% for 1996, 1995 and 1994) to pretax income is
reconciled as follows:

1996 1995 1994
(Thousands of Dollars)

Net income $190,482 $169,185 $152,043
Total income tax expense:
Charged to operating expenses 107,734 96,956 84,066
Charged (credited) to other income 442 294 (1,350)
Total pretax income $298,658 $266,435 $234,759

Income taxes on above at statutory
Federal income tax rate $104,530 $ 93,252 $ 82,166
Increases (decreases) attributable to:
State income taxes (less Federal
income tax effect) 9,684 8,880 7,555
Deferred income tax reversal at
higher than statutory rates (3,418) (3,310) (3,647)
Amortization of investment
tax credits (3,243) (3,230) (3,231)
Other differences, net 623 1,658 (127)
Total income tax expense $108,176 $ 97,250 $ 82,716

The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $501.7
million at December 31, 1996 and $468.9 million at December 31,
1995 are as follows:

1996 1995
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 46,503 $ 48,512
Cycle billing 19,799 19,143
Nuclear operations expenses 4,722 3,755
Deferred compensation 6,633 5,562
Other postretirement benefits 10,764 6,371
Other 6,579 2,929
Total deferred tax assets 95,000 86,272
Deferred tax liabilities:
Property plant and equipment 540,884 520,294
Pension expense 21,790 14,191
Reacquired debt 8,334 6,680
Research and experimentation 12,528 6,196
Deferred fuel 3,701 541
Other 9,483 7,260
Total deferred tax liabilities 596,720 555,162
Net deferred tax liability $501,720 $468,890

The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of SCANA Corporation through 1989, has
examined and proposed adjustments to SCANA's Federal returns for
1990 through 1992, and is currently examining SCANA's Federal
income tax returns for 1993 through 1995. The Company does not
anticipate that any adjustments which might result from these
examinations will have a significant impact on the results of
operations, cash flows 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, 1996 and 1995 are
as follows:

1996 1995
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
Cash and temporary cash
investments $ 5,399 $ 5,399 $ 6,798 $ 6,798
Investments 61 61 61 61
Liabilities:
Short-term borrowings 90,000 90,000 80,500 80,500
Long-term debt 1,319,513 1,352,939 1,315,412 1,412,213
Preferred stock (subject
to purchase or sinking funds) 45,446 44,342 48,682 46,603

The information presented herein is based on pertinent
information available to the Company as of December 31, 1996 and
1995. 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, 1996, 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.

Fair values of investments and long-term debt are based on
quoted market prices of the instruments or similar instruments,
or for those instruments for which there are no quoted market
prices available, fair values are based on net present value
calculations. 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) 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
committed lines of credit. Commercial paper borrowings are for
270 days or less. Details of lines of credit and short-term
borrowings, excluding amounts classified as long-term (Notes 3
and 4), at December 31, 1996, 1995 and 1994 and for the years
then ended are as follows:

1996 1995 1994
(Millions of dollars)

Authorized lines of credit at year-end $145.0 $165.0 $165.0
Unused lines of credit at year-end $145.0 $165.0 $165.0
Short-term borrowings outstanding at
year-end:
Commercial paper $ 90.0 $ 80.5 $100.0
Weighted average interest rate 5.53% 5.83% 6.04%

10. COMMITMENTS AND CONTINGENCIES:

A. Construction

SCANA and Westvaco Corporation have formed a limited
liability company, Cogen South LLC, to build and operate a $170
million cogeneration facility at Westvaco's Kraft Division Paper
Mill in North Charleston, South Carolina. The facility will
provide industrial process steam for the Westvaco paper mill and
shaft horsepower to enable the Company to generate up to 99
megawatts of electricity. Construction financing is being
provided to Cogen South LLC by banks. In addition to the
cogeneration LLC, Westvaco has entered into a 20-year contract
with the Company for all its electricity requirements at the
North Charleston mill at the Company's standard industrial rate.
Construction of the plant began in September 1996 and it is
expected to be operational in the fall of 1998.

B. Nuclear Insurance

The Price-Anderson Indemnification Act, which deals with the
Company's public liability for a nuclear incident, currently
establishes the liability limit for third-party claims associated
with any nuclear incident at $8.9 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. The Company'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.

The Company 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 $1.9 billion for any
losses at Summer Station. The Company pays annual premiums and,
in addition, could be assessed a retroactive premium not to
exceed 5 times its annual premium in the event of property damage
loss to any nuclear generating facilities covered under the NEIL
program. Based on the current annual premium, this retroactive
premium would not exceed $5.7 million.

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

C. Environmental

In September 1992 the Environmental Protection Agency (EPA)
notified the Company, the City of Charleston and the Charleston
Housing Authority of their potential liability for the
investigation and cleanup of the Calhoun Park Area site in
Charleston, South Carolina. This site originally encompassed
approximately eighteen acres and included properties which were
the locations for industrial operations, including a wood
preserving (creosote) plant and one of the Company'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,
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
investigation process to be compressed significantly. The PRPs
have negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study and a
corresponding Scope of Work. Field work began in November 1993
and a draft Remedial Investigation Report was submitted to the
EPA in February 1995. The Company resolved second and third
round comments and submitted a Final Draft Remedial Investigation
Report in October 1996. Although the Company is continuing to
investigate cost-effective cleanup methodologies, further work is
pending EPA approval of the Final Draft Remedial Investigation
Report.

In October 1996 the City of Charleston and the Company
settled all environmental claims the City may have had against
the Company involving the Calhoun Park area for a payment of $26
million over four years (1996-1999) by the Company to the City.
The Company is recovering the amount of the settlement, which
does not encompass site assessment and cleanup costs, through
rates in the same manner as other amounts accrued for site
assessments and cleanup (see Note 1L). As part of the
environmental settlement, the Company has agreed to construct an
1,100 space parking garage on the Calhoun Park site and to
transfer the facility to the City in exchange for a 20-year
municipal bond backed by revenues from the parking garage and a
mortgage on the parking garage. The total amount of the bond is
not to exceed $16.9 million, the maximum expected project cost.

The Company owns three other decommissioned manufactured gas
plant sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.

The Company is pursuing recovery of environmental
liabilities from appropriate pollution insurance carriers.

D. Franchise Agreements

See Note 3 for a discussion of an electric franchise
agreement between the Company and the City of Charleston.

E. Claims and Litigation

The Company is engaged in various claims and litigation
incidental to its business operations which management
anticipates will be resolved without material loss to the
Company. No estimate of the range of loss from these matters can
currently be determined.

11. SEGMENT OF BUSINESS INFORMATION:

Segment information at December 31, 1996, 1995 and 1994 and
for the years then ended is as follows:

1996
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $1,106,664 $234,825 $ 3,108 $1,344,597
Operating expenses,
excluding depreciation
and amortization 710,666 204,109 9,346 924,121
Depreciation and
amortization 122,581 12,107 263 134,951
Total operating expenses 833,247 216,216 9,609 1,059,072
Operating income (loss) $ 273,417 $ 18,609 $(6,501) 285,525

Add - Other income, net 4,120
Less - Interest charges, net 99,163
Net income $ 190,482

Capital expenditures:
Identifiable $196,891 $ 18,638 $ 443 $ 215,972

Utilized for overall Company operations 23,981
Total $ 239,953

Identifiable assets at
December 31, 1996:
Utility plant, net $2,869,642 $216,647 $ 1,875 $3,088,164
Inventories 75,838 2,104 423 78,365
Total $2,945,480 $218,751 $ 2,298 3,166,529

Other assets 792,273
Total assets $3,958,802

1995
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $1,006,566 $ 200,632 $ 3,889 $1,211,087
Operating expenses,
excluding depreciation
and amortization 657,452 169,768 10,429 837,649
Depreciation and
amortization 103,961 12,616 1,007 117,584
Total operating expenses 761,413 182,384 11,436 955,233
Operating income (loss) $ 245,153 $ 18,248 $ (7,547) 255,854

Add - Other income, net 9,553
Less - Interest charges, net 96,222
Net income $ 169,185

Capital expenditures:
Identifiable $ 245,016 $ 19,670 $ 265 $ 264,951

Utilized for overall Company operations 27,816
Total $ 292,767

Identifiable assets at
December 31, 1995:
Utility plant, net $2,850,647 $ 209,847 $ 1,878 $3,062,372
Inventories 76,697 2,155 561 79,413
Total $2,927,344 $ 212,002 $ 2,439 3,141,785

Other assets 660,648
Total assets $3,802,433

1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,526 $201,746 $ 4,002 $1,181,274
Operating expenses,
excluding depreciation
and amortization 659,610 173,717 10,577 843,904
Depreciation and
amortization 95,666 11,060 226 106,952
Total operating expenses 755,276 184,777 10,803 950,856
Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418

Add - Other income, net 7,271
Less - Interest charges, net 85,646
Net income $ 152,043
Capital expenditures:
Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780

Utilized for overall Company operations 20,167
Total $ 420,947

Identifiable assets at
December 31, 1994:
Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956
Inventories 85,113 2,605 495 88,213
Total $2,802,260 $203,623 $ 2,286 3,008,169

Other assets 578,922
Total assets $3,587,091

12. QUARTERLY FINANCIAL DATA (UNAUDITED):

1996
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $354,264 $310,566 $364,570 $315,197 $1,344,597
Operating income 79,479 59,154 90,235 56,657 285,525
Net Income 56,084 35,197 66,122 33,079 190,482

1995
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $308,759 $275,139 $339,937 $287,252 $1,211,087
Operating income 67,189 53,153 87,023 48,489 255,854
Net Income 45,249 30,870 65,040 28,026 169,185

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

NONE
PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS

The directors listed below were elected April 25, 1996 to hold office
until the next annual meeting of the Company's stockholders on April 24, 1997.

Name and Year First
Became Director Age Principal Occupation; Directorships

Bill L. Amick 53 For more than five years, Chairman of the
(1990) Board and Chief Executive Officer of Amick
Farms, Inc., Batesburg, SC (vertically
integrated broiler operation).

For more than five years, Chairman and Chief
Executive Officer of Amick Processing,
Inc. and Amick Broilers, Inc.

Director, SCANA Corporation, Columbia,
SC.

William B. Bookhart, Jr. 55 For more than five years, a partner in
(1979) Bookhart Farms, Elloree, SC (general
farming).

Director, SCANA Corporation, Columbia, SC.

William T. Cassels, Jr. 67 For more than five years, Chairman of the
(1990) Board, Southeastern Freight Lines, Inc.,
Columbia, SC (trucking business).

Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; Wachovia Bank of South
Carolina, N.A., Columbia, SC.

Hugh M. Chapman 64 For more than five years, Chairman of
(1988) NationsBank South, Atlanta, GA (a division
of NationsBank Corporation, bank holding
company).

Director, SCANA Corporation, Columbia, SC.

Name and Year First
Became Director Age Principal Occupation; Directorships

James B. Edwards, D.M.D. 69 For more than five years, President and
(1986) Professor of Maxillofacial Surgery,
Medical University of South Carolina,
Charleston, SC.

U.S. Secretary of Energy from January 1981
to November 1982.

Governor of South Carolina, 1975-1979.

Director, Phillips Petroleum Co.,
Bartlesville, OK; WMX Technologies, Inc.,
Oak Brook, IL; General Engineering
Laboratories, Inc., Charleston SC;
GS Industries, Inc., Charlotte, NC; IMO
Industries, Inc., Lawrenceville, NJ;
National Data Corporation, Atlanta, GA;
SCANA Corporation, Columbia, SC.

Elaine T. Freeman 61 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg,
S.C.

Director National Bank of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.

Lawrence M. Gressette, Jr. 65 For more than five years, Chairman of the
(1987) Board and Chief Executive Officer
of SCANA Corporation and Chairman
of the Board and Chief Executive
Officer of all SCANA subsidiaries,
including the Company.

For more than five years prior to
December 13, 1995, President of
SCANA Corporation.

Director, Wachovia Corporation, Winston-
Salem, NC; InterCel, Inc., West Point, GA;
The Liberty Corporation, Greenville, SC;
SCANA Corporation, Columbia, SC.

Benjamin A. Hagood 69 Since January 1, 1993, Chairman of the
(1974) Board, William M. Bird and Company, Inc.,
Charleston, SC (wholesale distributor
of floor covering material).

For more than one year prior to January 1,
1993, President and Director, William M.
Bird and Company, Inc., Charleston, SC.

Director, SCANA Corporation, Columbia, SC.

Name and Year First
Became Director Age Principal Occupation; Directorships

W. Hayne Hipp 57 For more than five years, President and
(1983) Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance
and broadcasting holding company).

Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.

F. Creighton McMaster 67 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).

Director, First Union National Bank of
South Carolina, Greenville, SC; SCANA
Corporation, Columbia, SC.

Henry Ponder, Ph.D. 68 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Suntrust Banks, Inc., Nashville,
TN; SCANA Corporation, Columbia, SC.

John B. Rhodes 66 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC
(distributor of petroleum products).

Director, SCANA Corporation, Columbia, SC.

William B. Timmerman 50 Since December 13, 1995, President of SCANA
(1991) Corporation.

From May 1, 1994 to December 13, 1995,
Executive Vice President of SCANA
Corporation.

Since August 25, 1993, Assistant Secretary
ofSCANA Corporation and all of its
subsidiaries, including the Company.

From August 28, 1991 to February 20, 1996,
Chief Financial Officer of the Company.

For more than five years prior to May 1,
1994, Senior Vice President of SCANA
Corporation.

For more than five years prior to February
20, 1996, Controller of SCANA Corporation.

Director, SCANA Corporation, Columbia, SC;
InterCel, Inc., West Point, GA and
Wachovia Bank of South Carolina,
Columbia, S. C.

E. Craig Wall, Jr. 59 For more than five years, President and
(1982) Director, Canal Industries, Conway, SC
(forest products industry).

Director, Sonoco Products Company,
Hartsville, SC; Ruddick Corporation,
Charlotte, NC; NationsBank Corp.,
Charlotte, NC; Blue Cross/
Blue Shield of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.

EXECUTIVE OFFICERS OF THE COMPANY

The Company's officers are elected at the annual organizational meeting
of the Board of Directors and hold office until the next such organizational
meeting,unless the Board of Directors shall otherwise determine, or unless a
resignation is submitted.
Positions Held During
Name Age Past Five Years Dates

L. M. Gressette, Jr. (1) 65 Chairman of the Board and
Chief Executive Officer *-present
President of SCANA *-1995

W.B. Timmerman (1) 50 President and Chief Operating
Officer of SCANA 1995-present
President of SCANA
Communications, Inc.,
an affiliate 1996-present
Executive Vice President, 1994-1995
SCANA
Assistant Secretary 1993-1996
Chief Financial Officer *-1996
Controller, SCANA *-1996
Senior Vice President, *-1994
SCANA
J. L. Skolds 46 President and Chief
Operating Officer 1996-present
Senior Vice President -
Generation 1994-1996
Vice President - Nuclear
Operations *-1994

G.J. Bullwinkel, Jr. 48 Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production 1993-1994
Senior Vice President-
Production *-1992

W.A. Darby 51 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-1996
President and Treasurer of
ServiceCare 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-present

K. B. Marsh (1) 41 Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-present
Vice President - Finance,
Treasurer and Secretary *-1996

B.T. Zeigler (1) 41 Vice President - SCANA 1996-present
General Counsel 1995-present
Associate General Counsel 1992-1995
Partner - Lewis, Babcock &
Hawkins Law Firm *-1992

*Indicates position held at least since March 1, 1992

(1) On October 22, 1996 the Board of Directors elected W. B. Timmerman
to be Chairman of the Board and Chief Executive Officer effective
March 1, 1997 upon the retirement of L. M. Gressette, Jr. Mr.
Timmerman continues to serve as President of SCANA.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

All of the Company's common stock is held by its parent, SCANA
Corporation. The required forms indicate that no equity securities of
the Company are owned by its directors and executive officers. Based
solely on a review of the copies of such forms and amendments
furnished to the Company and written representations from the
executive officers and directors, the Company believes that during
1996 all Section 16(a) filing requirements applicable to its executive
officers, directors and greater than 10% beneficial owners were
complied with.

ITEM 11. EXECUTIVE COMPENSATION

The following table contains information with respect to compensation
paid or accrued during the years 1996, 1995 and 1994 to the Chief Executive
Officer of the Company, to each of the other four most highly compensated
executive officers of the Company during 1996 who were serving as executive
officers of the Company at the end of 1996 and to Bruce D. Kenyon, former
President and Chief Operating Officer, South Carolina Electric and Gas Company,
who retired from the Company on September 1, 1996.

SUMMARY COMPENSATION TABLE

Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2)
Salary Bonus Other Payouts
($) ($) Annual (3) (4)
Compensation LTIP All Other
($) Payouts Compensation
($) ($)

L. M. Gressette, Jr. 1996 483,952(5) 274,320 50,998 285,408 29,037
Chairman of the Board, 1995 449,246 197,500 65,779 390,156 26,955
Chief Executive Officer 1994 416,609 0 2,255 173,375 24,996

W. B. Timmerman 1996 335,266 196,832 6,399 109,819 20,116
President and Chief 1995 254,214 101,588 987 150,353 15,127
Operating Officer - 1994 235,099 19,725 5,524 70,751 14,106
SCANA Corporation

J. L. Skolds 1996 215,708 114,099 2,453 55,513 12,943
President and Chief 1995 176,156 74,151 54 76,128 10,569
Operating Officer 1994 156,731 0 4,215 38,249 9,404

G. J. Bullwinkel 1996 205,980 90,370 3,710 66,374 12,359
Senior Vice President 1995 189,097 70,904 487 90,402 11,346
- - Retail Electric 1994 170,828 50,765 3,907 38,249 9,826

J. H. Young 1996 182,990 63,056 7,873 66,374 10,979
Senior Vice President 1995 176,998 53,170 850 90,402 13,620
- -Business Development 1994 174,771 50,765 8,119 45,251 10,054

B. D. Kenyon 1996 229,820 92,012 7,989 131,240 106,304
former President and 1995 318,542 104,353 7,107 172,240 19,113
Chief Operating Officer 1994 313,581 96,768 10,638 81,619 18,815
______________
(1) Payments under the annual Performance Incentive Plan described hereafter.
(2) For 1996, other annual compensation consists of life insurance premiums on policies owned
by named executive officers and payments to cover taxes on benefits of $50,018 and $980
for Mr. Gressette; $4,201 and $2,198 for Mr. Timmerman; $2,070 and $383 for Mr. Skolds;
$3,171 and $539 for Mr. Bullwinkel; $7,800 and $73 for Mr. Young and $7,989 and $0 for
Mr. Kenyon.
(3) Payments under the long-term Performance Share Plan described hereafter.
(4) All other compensation for all named executive officers consists of Company contributions
to defined contribution plans based on the funding formula applicable to all Company
employees and for Mr. Kenyon, 1996 early retirement payment of $55,850, and $36,665,
representing the value of certain property which was transferred to Mr. Kenyon upon his
leaving the Company. Mr. Kenyon will receive early retirement benefits of $13,962 per
month reduced by all amounts received under the Company's Retirement Plan, his SERP or
Social Security.
(5) Reflects actual salary paid in 1996. Base salary of $496,000, became effective in May of
1996.

Long-Term Performance Share Plan

The long-term Performance Share Plan for officers of SCANA and
its subsidiaries measures SCANA's Total Shareholder Return ("TSR")
relative to a group of peer companies over a three-year period. The
"PSP Peer Group" includes 94 electric and gas utilities, none of which
have annual revenues of less than $100 million.

TSR is stock price increase over the three-year period, plus cash
dividends paid during the period, divided by stock price as of the
beginning of the period. Comparing SCANA's TSR to the TSR of a large
group of other utilities reflects SCANA's recognition that investors
could have invested their funds in other utility companies and
measures how well SCANA did when compared to others operating in
similar interest, tax, economic and regulatory environments.

Executives eligible to participate in the Performance Share Plan
are assigned target award opportunities at the beginning of each
three-year period based primarily on their salary level. In
determining award sizes, levels of responsibilities and competitive
practices also are considered. Awards under this plan represent a
significant portion of executives "at-risk" compensation. To provide
additional incentive for executives, and to ensure that executives are
only rewarded when shareholders gain, actual payouts may exceed the
median of the market when performance is above the 50th percentile of
the peer group. For lesser performance, awards will be at or below
the market median.

Payouts occur when SCANA's TSR is in the top two-thirds of the
PSP Peer Group, and vary based on SCANA's ranking against the peer
group. Executives earn threshold payouts of 0.4 times target at the
33rd percentile of three-year performance. Target payouts will be
made at the 50th percentile of three-year performance. Maximum
payouts will be made at 1.5 times target when SCANA's TSR is at or
above the 75th percentile of the peer group. No payouts will be
earned if performance is at less than the 33rd percentile. Awards are
denominated in shares of SCANA Common Stock and may be paid in either
stock, cash or a combination of stock and cash.

For the three-year period from 1994 through 1996, SCANA's TSR was
at the 69th percentile of the PSP Peer Group. This resulted in
payouts at 138% of target shares awarded to be paid in a combination
of stock and cash.

The following table shows the target awards made in 1996 for
potential payment in 1999 under the long-term Performance Share Plan,
and estimated future payouts under that plan at threshold, target and
maximum levels for the named executive officers. Mr. Gressette's and
Mr. Kenyon's estimated future payouts will be reduced to reflect their
retirements.

LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1996 TO BE PAID IN 1999

Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name Rights (#) or Payout
Threshold Target Maximum
($ or #) ($ or #) ($ or #)

L. M. Gressette, Jr. 8,340 1996-1998 1,297 3,243 4,865
W. B. Timmerman 6,150 1996-1998 2,460 6,150 9,225
B. D. Kenyon 3,920 1996-1998 348 871 1,307
J. L. Skolds 2,340 1996-1998 936 2,340 3,510
G. J. Bullwinkel 2,340 1996-1998 936 2,340 3,510
J. H. Young 1,840 1996-1998 736 1,840 2,760

DEFINED BENEFIT PLANS

In addition to the qualified Retirement Plan for all
employees, the Company has Supplemental Executive Retirement
Plans ("SERPs") for certain eligible employees, including
officers. A SERP is an unfunded plan which provides for benefit
payments in addition to those payable under a qualified
retirement plan. It maintains uniform application of the
Retirement Plan benefit formula and would provide, among other
benefits, payment of Retirement Plan formula pension benefits, if
any, which exceed those payable under the Internal Revenue Code
("IRC") maximum benefit limitations.

The following table illustrates the estimated maximum annual
benefits payable upon retirement at normal retirement date under
the Retirement Plan and the SERPs.

Pension Plan Table

Final Service Years
Average Pay 15 20 25 30 35

$150,000 $ 42,143 $ 56,190 $ 70,238 $ 84,286 $ 87,083
200,000 57,143 76,190 95,238 114,286 118,333
250,000 72,143 96,190 120,238 144,286 149,583
300,000 87,143 116,190 145,238 174,286 180,833
350,000 102,143 136,190 170,238 204,286 212,083
400,000 117,143 156,190 195,238 234,286 243,333
450,000 132,143 176,190 220,238 264,286 274,583
500,000 147,143 196,190 245,238 294,286 305,833
550,000 162,143 216,190 270,238 324,286 337,083
600,000 177,143 236,190 295,238 354,286 368,333
650,000 192,143 256,190 320,238 384,286 299,583
700,000 207,143 276,190 345,238 414,286 430,833
750,000 222,143 296,190 370,238 444,286 462,083
800,000 237,143 316,190 395,238 474,286 493,333
850,000 252,143 336,190 420,238 504,286 524,583
900,000 267,143 256,190 445,238 534,286 555,833
950,000 282,143 376,190 470,238 564,286 587,083
1,000,000 297,143 396,190 495,238 594,286 618,333

The compensation shown in the column labeled "Salary" of the
Summary Compensation Table for all the named executive officers
except Mr. Gressette is covered by the Retirement Plan and/or a
SERP. The compensation shown in the columns labeled "Salary" and
"Bonus" for Mr. Gressette are covered by the Retirement Plan
and/or SERP. As of December 31, 1996, Messrs. Gressette,
Timmerman, Bullwinkel, Skolds, Young and Kenyon had credited
service under the Retirement Plan (or its equivalent under the
SERP) of 34, 18, 25, 10, 34 and 23 years, respectively. Benefits
are computed based on a straight-life annuity with an unreduced
60% surviving spouse benefit. The amounts in this table assume
continuation of the primary Social Security benefits in effect at
January 1, 1997 and are not subject to any deduction for Social
Security or other offset amounts.

The Company also has a Key Employee Retention Program (the
"Key Employee Retention Program") covering officers and certain
other executive employees that provides supplemental retirement
and/or death benefits for participants. Under the program, each
participant may elect to receive either a monthly retirement
benefit for 180 months upon retirement at or after age 65 equal
to 25% of the average monthly salary of the participant over his
final 36 months of employment prior to age 65, or an optional
death benefit payable to a participant's designated beneficiary
monthly for 180 months, in an amount equal to 35% of the average
monthly salary of the participant over his final 36 months of
employment prior to age 65. In the event of the participant's
death prior to age 65, the Company will pay to the participant's
designated beneficiary for 180 months, a monthly benefit equal to
50% of such participant's base monthly salary in effect at death.

All of the executive officers named in the Summary
Compensation Table are participating in the program. Mr.
Gressette is now receiving annual benefits of $113,855 under the
program. In connection with his early retirement, the Company
agreed to begin Mr. Kenyon's payments under the program on
September 1, 1996. He will receive annual payments of $79,412
until September 1, 2011. The estimated annual retirement
benefits payable at age 65 based on projected eligible
compensation (assuming increases of 4% per year) to the other
persons named in the Summary Compensation Table are as follows:
Mr. Timmerman - $147,017; Mr. Bullwinkel - $95,496; Mr. Skolds -
$122,777; and Young - $54,424.

TERMINATION, SEVERANCE AND CHANGE OF CONTROL ARRANGEMENTS

At its December 18, 1996 meeting, the Board of Directors of
the Company approved the SCANA Corporation Executive Benefit Plan
Trust Agreement (the "Trust"). The purpose of the Trust is to
protect the deferred compensation benefits of certain directors,
executives and other key employees of the Company in the event of
a Change in Control (as defined in the Trust). Executive
officers named in the Summary Compensation Table participate in
certain plans and agreements listed below (the "Plans") covered
by the Trust:

(1) SCANA Corporation Voluntary Deferral Plan
(2) SCANA Corporation Supplementary Voluntary Deferral Plan
(3) SCANA Corporation Key Executive Severance Benefits Plan
(4) SCANA Corporation Key Employee Retention Plan
(5) SCANA Corporation Supplemental Executive Retirement
Plan
(6) South Carolina Electric & Gas Company Supplemental
Executive
Retirement Plan
(7) Individual Supplemental Executive Retirement Plan
Agreements

When a Potential Change in Control (as defined in the Trust)
occurs, the Company is required to pay into the Trust an amount
equal to the sum of (i) 125% of the estimated deferred
compensation benefits payable under each Plan and (ii) the
estimated federal, state and local income taxes and excise taxes
payable by Plan participants on those benefits. Recalculations
are required to be made at least once every three months and
funding adjusted appropriately. The Trust provides for lump sum
distributions to be made to Plan participants within 30 business
days following written notification to the Trustee that a Change
in Control has occurred.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During 1996, no officer, employee or former officer of the
Company or any of its affiliates served as a member of the Long-
Term Compensation Committee or the Management Development and
Corporate Performance Committee ("Performance Committee"), except
Mr. Gressette who served as a member of the Performance
Committee. Although Mr. Gressette was an ex-officio, nonvoting
member of the Performance Committee during 1996, he did not
participate in any of its decisions concerning executive officer
compensation.

Since January 1, 1996, the Company has engaged in business
transactions with entities with which Mr. Chapman (Chairman of
both the Performance Committee and the Long-Term Compensation
Committee), Mr. McMaster (a member of the Long-Term Compensation
Committee) and Mr. Rhodes (a member of the Performance Committee
and the Long-Term Compensation Committee) are executive officers.

Mr. Chapman is Chairman of NationsBank South, a division of NationsBank
Corporation. Since January 1, 1996, the Company has engaged in various
transactions in which affiliates of NationsBank Corporation acted as lender or
provider of lines of credit or credit support to the Company and its
affiliates. The amount paid during 1996 by the Company and its affiliates to
NationsBank Corporation affiliates on account of such transactions was
$1,034,320. In addition, during 1996 a NationsBank Corporation affiliate and
a Company affiliates have engaged in options and futures transactions and
forward contracts relating to forecasted natural gas production. The amount
paid during 1996 by the Company's affiliate to NationsBank Corporation
affiliates on account of such transactions was $10,814,458. It is anticipated
that similar transactions will continue in the future.

Mr. McMaster is the President and Manager of Winnsboro
Petroleum Company. Purchases from Winnsboro Petroleum Company
totaling $81,405 for petroleum products were made during 1996 by
the Company and its affiliates. It is anticipated that similar
transactions will continue in the future.

Mr. Rhodes is the Chairman and Chief Executive Officer of
Rhodes Oil Company. Purchases from Rhodes Oil Company totaling
$80,059 for petroleum products were made during 1996 by the
Company and its affiliates. It is anticipated that similar
transactions will continue in the future.

Compensation of Directors

Fees. During 1996, directors who were not employees of the
Company or SCANA Corporation were paid $17,600 annually for
services rendered, plus $1,800 for each Board meeting attended
and $850 for attendance at a committee meeting which is not held
on the same day as a regular meeting of the Board. The fee for
attendance at a telephone conference meeting is $200. The fee
for attendance at a conference is $850. In addition, directors
are paid, as part of their compensation, travel, lodging and
incidental expenses related to attendance at meetings and
conferences. The Board of Directors approved a Plan effective
January 1, 1997 whereby non-employee directors receive on a
quarterly basis, 41% of their retainer in shares of SCANA's
common stock. The purpose of the Plan is to promote the
achievement of long-term objectives of the Company by linking the
personal interests of the non-employee directors to those of
SCANA's shareholders by paying a portion of director compensation
in stock. SCANA believes this linkage will further promote the
achievement of its long-term objectives. Directors who are
employees of the Company or its affiliates receive no
compensation for serving as directors or attending meetings.

Deferral Plan. SCANA has a plan pursuant to which directors
may defer all or a portion of their fees paid to them in cash for
services rendered and meeting attendance. Interest is earned on
the deferred amounts at a rate set by the Performance Committee.
During 1996 and currently, the rate is set at the announced prime
rate of Wachovia Bank of South Carolina. Mr. Cassels, Mr. Hagood
and Mr. Rhodes were the only directors participating in the plan
during 1996. Mr. Cassels became a participant in January 1994,
Mr. Hagood in July, 1996 and Mr. Rhodes in July 1987, and
interest credited to their deferral accounts during 1996 was
$5,974, $378 and $22,497, respectively.

Endowment Plan. Each director participates in the
Directors' Endowment Plan, which provides that SCANA make a tax
deductible, charitable contribution totaling $500,000 to
institutions of higher education nominated by the director. A
portion is contributed upon retirement of the director and the
remainder upon the director's death. The plan is funded in part
through insurance on the lives of the directors. Designated in-
state institutions of higher education must be approved by the
Chief Executive Officer of SCANA. Any out-of-state designation
must be approved by the Performance Committee. The designated
institutions are reviewed on an annual basis by the Chief
Executive Officer to assure compliance with the intent of the
program. The plan is intended to reinforce SCANA's commitment to
quality higher education and is intended to enhance SCANA's
ability to attract and retain qualified board members.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

The table set forth below indicates the shares of SCANA's
common stock beneficially owned as of March 10, 1997 by each
director, each of the persons named in the Summary Compensation
Table on page 61, and the current directors and executive
officers of the Company as a group.

SECURITY OWNERSHIP OF MANAGEMENT

Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature
Owner of Ownership 1 Owner of Ownership 1
B. L. Amick 2,653 W. Hayne Hipp 2,870
W. B. Bookhart, Jr. 16,709 J. H. Young 15,743
G. J. Bullwinkel 18,187 F. C. McMaster 5,700
W. T. Cassels, Jr. 2,070 L. M. Miller 1,000
H. M. Chapman 6,070 Henry Ponder 13,723
J. B. Edwards 4,845 J. B. Rhodes 8,283
E. T. Freeman 4,390 J. L. Skolds 6,988
L. M. Gressette, Jr. 49,792 W. B. Timmerman 30,422
B. A. Hagood 2,483 E. C. Wall 17,070
B. D. Kenyon* 20,613

All directors and executive officers as a group (20 persons) TOTAL 237,366.
TOTAL PERCENT OF CLASS 0.2%

* Bruce D. Kenyon, former President and Chief Operating Officer,
South Carolina Electric & Gas Company, retired these positions on
September 1, 1996.

The information set forth above as to the security ownership
has been furnished to the Company by such persons.
_____________________
1 Includes shares owned by close relatives, the beneficial
ownership of which is disclaimed by the director or nominee, as
follows:
Mr. Amick - 480; Mr. Bookhart - 4,748; Mr. Gressette - 1,060;
Mr. Hagood - 341; Mr. McMaster - 2,000.

Includes shares purchased through December 31, 1996, but not
thereafter, by the Trustee under the SCANA Corporation Stock
Purchase Savings Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information regarding certain relationships and related
transactions, see Item 11, "Compensation Committee Interlocks and
Insider Participation."

PART IV

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

Financial Statements and Schedules

See Index to Consolidated Financial Statements and
Supplementary Data on page 30.

Exhibits Filed

Exhibits required to be filed with this Annual Report on
Form 10-K are listed in the Exhibit Index following the signature
page. Certain of such exhibits which have heretofore been filed
with the Securities and Exchange Commission and which are
designated by reference to their exhibit number in prior filings
are hereby incorporated herein by reference and made a part
hereof.

As permitted under Item 601(b)(4)(iii), instruments defining
the rights of holders of long-term debt of less than 10 percent
of the total consolidated assets of 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

None

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) SOUTH CAROLINA ELECTRIC & GAS COMPANY

BY (SIGNATURE) s/Bruce D. KenyonJ. L. Skolds
(NAME AND TITLE) Bruce D. Kenyon,J. L. Skolds, President and Chief
Operating Officer
DATE April 26, 1995

2February 18, 1997

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 and Director
DATE February 18, 1997

(ii) Principal financial officer:

BY (SIGNATURE) s/K. B. Marsh
(NAME AND TITLE) K. B. Marsh, Chief Financial Officer
DATE February 18, 1997

(iii) Principal accounting officer:

BY (SIGNATURE) s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and Controller
DATE February 18, 1997

BY (SIGNATURE) s/B. L. Amick
(NAME AND TITLE) B. L. Amick, Director
DATE February 18, 1997

BY (SIGNATURE) s/W. B. Bookhart, Jr.
(NAME AND TITLE) W. B. Bookhart, Jr., Director
DATE February 18, 1997

BY (SIGNATURE) s/W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 18, 1997

BY (SIGNATURE) s/H. M. Chapman
(NAME AND TITLE) H. M. Chapman, Director
DATE February 18, 1997

BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 18, 1997

BY (SIGNATURE) s/E. T. Freeman
(NAME AND TITLE) E. T. Freeman, Director
DATE February 18, 1997

BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 18, 1997

BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 18, 1997

BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 18, 1997

BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 18, 1997

BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Director
DATE February 18, 1997

BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 18, 1997

BY (SIGNATURE) s/E. C. Wall, Jr.
(NAME AND TITLE) E. C. Wall, Jr., Director
DATE February 18, 1997

SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially
EXHIBIT INDEX Numbered

Number Pages
2. Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Not Applicable

3. Articles of Incorporation and By-Laws

A. Restated Articles of Incorporation of the
Company as adopted on June 9, 1994December 15, 1993
(Exhibit 3-A to Form 10-Q for the quarter
ended June 30, 1994, File No. 1-3375)............................................................. #
B. Articles of Amendment, dated June 7, 1994,
filed June 9, 1994 (Exhibit 3-B to Form 10-Q
for the quarter ended June 30, 1994, File No. 1-3375).... #
C. Articles of Amendment, dated November 9, 1994
(Filed herewith)......................................... 69(Exhibit 3-C to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
D. Articles of Amendment, dated December 9, 1994
(Filed herewith)......................................... 71(Exhibit 3-D to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
E. Articles of Correction, dated January 17, 1995
(Filed herewith)......................................... 73(Exhibit 3-E to Form 10-K for the year ended
December 31, 1994, File No. 1-3375)...................... #
F. Articles of Amendment, dated January 13, 1995
and filed January 17, 1995 (Exhibit 3-F to
Form 10-K for the year ended December 31, 1994,
File No. 1-3375)......................................... #
G. Articles of Amendment dated March 31, 1995
(Exhibit 3-G to Form 10-Q for the quarter
ended March 31, 1995, File No. 1-3375)................... #
H. Articles of Correction - Amendment to Statement
filed March 31, 1995, dated December 13, 1995
(Filed herewith)........................................................ 74
G.I. Articles of Amendment dated December 13, 1995
(Filed herewith)......................................... 75
J. Articles of Amendment dated February 21, 1997
(Filed herewith)......................................... 77
K. Copy of By-Laws of the Company as revised and
amended thru December 15, 1993 (Exhibit 3-AZ to
Form 10-K for the year ended December 31, 1993,
File No. 1-3375)......................................... #June 18, 1996 (Filed herewith).............. 79

4. Instruments Defining the Rights of Security
Holders, Including Indentures
A. 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)................................ #
B. Fourth Supplemental Indenture dated as of April 1,
1950, to Indenture referred to in Exhibit 4A,
pursuant to which the Company assumed said
Indenture (Exhibit 2-C to Registration No. 2-26459)...... #
C. Fifth through Fifty-second Supplemental Indentures
to Indenture referred to in Exhibit 4A dated as
of the dates indicated below and filed as
exhibits to the Registration Statements and
1934 Act reports whose file numbers 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

# Incorporated herein by reference as indicated.

SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
4. (continued)
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
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

# Incorporated herein by reference as indicated.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

Exhibit Index (Continued)
Sequentially
Numbered
r Pages

4. (continued)
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
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
D. 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)......................................... #
E. First Supplemental Indenture to Indenture referred to
in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-49421)......................... #
F. Second Supplemental Indenture to Indenture referred to
in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G
to Registration Statement No. 33-57955)......................... #

9. Voting Trust Agreement
Not Applicable

10. Material Contracts
A. Copy of Supplemental Executive Retirement Plan
(Exhibit 10-A to Form 10-K for the year ended
December 31, 1980)............................................ #

# Incorporated herein by reference as indicated.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
11. Statement Re Computation of Per Share Earnings
Not Applicable

12. Statement re Computation of Ratios (Filed herewith)............... 76........ 95

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

# Incorporated herein by reference as indicated.

SOUTH CAROLINA ELECTRIC & GAS COMPANY

Exhibit Index (Continued)
Sequentially
Numbered
Number Pages

18. Letter Re Change in Accounting Principles
Not Applicable

21. Subsidiaries of the Registrant
Not Applicable

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

23. Consents of Experts and Counsel
Consent of Deloitte & Touche LLP........................... 80LLP.......................... 99

24. Power of Attorney
Not Applicable

27. Financial Data Schedule
Filed herewith

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

99. Additional Exhibits
Not Applicable

# Incorporated herein by reference as indicated.

571