**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


**Washington,
      DC 20549**




**FORM
      10-Q**




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





For
      the
      quarterly period ended June 30, 2007





OR





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





For
      the
      Transition Period
      fromto











Commission
            Registrant,
                State of Incorporation,
            I.R.S.
                EmployerFile
                Number
            Address
                and Telephone Number
            Identification
                No.1-8809
            SCANA
                Corporation
            57-0784499(a
                South Carolina corporation)1426
                Main Street, Columbia, South Carolina 29201(803)
                217-90001-3375
            South
                Carolina Electric & Gas Company
            57-0248695(a
                South Carolina corporation)1426
                Main Street, Columbia, South Carolina 29201(803)
                217-9000





Indicate
      by check mark whether the registrants: (1) have filed all reports required
      to be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrants were
      required to file such reports), and (2)
      have
      been subject to such filing requirements for the past 90 days.


SCANA
      Corporation Yes x
      No **□** South
      Carolina Electric & Gas Company Yes x No **□**





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See definitions of “accelerated
      filer” and “large accelerated filer” in Rule 12b-2 of the Exchange
      Act.





SCANA
                Corporation
            Large
                accelerated filer x
            Accelerated
                filer **□**
            Non-accelerated
                filer **□**South
                Carolina Electric & Gas Company
            Large
                accelerated filer **□**
            Accelerated
                filer **□**
            Non-accelerated
                filer x





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12b-2 of the Exchange Act).


SCANA
      Corporation Yes **□** No
x 
South
      Carolina
      Electric & Gas Company Yes **□******No x





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




Description
                of
            Shares
                OutstandingRegistrant
            Common
                Stock
            at
                July 31, 2007SCANA
                Corporation
            Without
                Par Value
            116,664,933South
                Carolina Electric & Gas Company
            $4.50
                Par Value
            40,296,147 (a)(a)Owned
                beneficially and of record by SCANA Corporation.





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







Table
          of Contents





**TABLE
      OF CONTENTS**





**JUNE
      30, 2007**








Page**Cautionary
                Statement Regarding Forward-Looking
                Information****PART I.
                FINANCIAL INFORMATION****SCANA
                Corporation Financial
                Section**
            4Item
                1.
            Financial
                Statements
            5Condensed
                Consolidated Balance
                Sheets
            5Condensed
                Consolidated Statements of
                Income
            7Condensed
                Consolidated Statements of Cash
                Flows
            8Condensed
                Consolidated Statements of
                Comprehensive Income
            9Notes
                to Condensed Consolidated Financial
                Statements
            10Item
                2.
            Management’s
                Discussion and Analysis of Financial Conditionand Results of Operations
            19Item
                3.
            Quantitative
                and Qualitative Disclosures About Market
                Risk
            25Item
                4.
            Controls
                and Procedures
            26**South
                Carolina Electric & Gas Company Financial
                Section**
            27Item
                1.
            Financial
                Statements
            28Condensed
                Consolidated Balance
                Sheets
            28Condensed
                Consolidated Statements of
                Income
            30Condensed
                Consolidated Statements of Cash
                Flows
            31Notes
                to Condensed Consolidated Financial
                Statements
            32Item
                2.
            Management’s
                Discussion and Analysis ofFinancial
                Condition and Results of Operations
            40Item
                3.
            Quantitative
                and Qualitative Disclosures About MarketRisk
            44Item
                4T.
            Controls
                and Procedures
            45**PART
                II. OTHER INFORMATION**
            46Item
                2.
            Unregistered
                Sales of Equity Securities and Use of Proceeds
            46Item
                4.
            Submission
                of Matters to a Vote of Security Holders
            46Item
                6.
            Exhibits
            47Signatures
            48Exhibit
                Index
            49











Table
          of Contents


**CAUTIONARY
      STATEMENT REGARDING FORWARD-LOOKING
      INFORMATION**





Statements
      included in this Quarterly Report on Form 10-Q which are not statements of
      historical fact are intended to be, and are hereby identified as,
      "forward-looking statements" for purposes of Section 27A of the Securities
      Act of 1933, as amended, and Section 21E of the Securities Exchange Act of
      1934, as amended. Forward-looking statements include, but are not limited to,
      statements concerning key earnings drivers, customer growth, environmental
      regulations and expenditures, leverage ratio, projections for pension fund
      contributions, financing activities, access to sources of capital, impacts
      of
      the adoption of new accounting rules, estimated construction and other
      expenditures and factors affecting the availability of synthetic fuel tax
      credits. In some cases, forward-looking statements can be identified by
      terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,”
“anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or
“continue” or the negative of these terms or other similar terminology. Readers
      are cautioned that any such forward-looking statements are not guarantees of
      future performance and involve a number of risks and uncertainties, and that
      actual results could differ materially from those indicated by such
      forward-looking statements. Important factors that could cause actual results
      to
      differ materially from those indicated by such forward-looking statements
      include, but are not limited to, the following:





(1)       the
      information is of a preliminary nature and may be subject to further and/or
      continuing review and adjustment;





(2)       regulatory
      actions, particularly changes in rate regulation and environmental
      regulations;





(3)       current
      and future litigation;





(4)       changes
      in the economy, especially in areas served by subsidiaries of SCANA Corporation
      (SCANA);





(5)       the
      impact of competition from other energy suppliers, including competition from
      alternate fuels in industrial


interruptible markets;





(6)       growth
      opportunities for SCANA's regulated and diversified subsidiaries;





(7)       the
      results of financing efforts;





(8)       changes
      in SCANA’s or its subsidiaries’ accounting rules and accounting
      policies;





(9)       weather
      conditions, especially in areas served by SCANA's subsidiaries;





(10)      payment
      by counterparties as and when due;





(11)      the
      availability of fuels such as coal, natural gas and enriched uranium used to
      produce electricity; the availability


of purchased power and natural gas for
      distribution; the level and volatility of future market prices for such
      fuels


and purchased power; and the ability to recover the
      costs for such fuels and purchased power;





(12)      performance
      of SCANA's pension plan assets;





(13)      inflation;





(14)      compliance
      with regulations; and





(15)      the
      other risks and uncertainties described from time to time in the periodic
      reports filed by SCANA or South


Carolina Electric & Gas Company (SCE&G) with the United States
      Securities and Exchange Commission (SEC).





**SCANA
      and SCE&G disclaim any obligation to update any forward-looking
      statements.**







Table
          of Contents










































































**SCANA
      CORPORATION**


**FINANCIAL
      SECTION**




































































Table
          of Contents


**PART I.  FINANCIAL
      INFORMATION**





**ITEM
      1.  FINANCIAL STATEMENTS**








SCANA
      CORPORATION


CONDENSED
      CONSOLIDATED BALANCE SHEETS


(Unaudited)





June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006AssetsUtility
                  Plant In Service
            
            $
            9,494
            
            
            $
            9,227Accumulated
                  Depreciation and Amortization
            
            
            (2,923
            )
            
            
            (2,815
            )6,571
            
            
            
            6,412Construction
                  Work in Progress
            
            
            312
            
            
            
            326Nuclear
                  Fuel, Net of Accumulated Amortization
            
            
            66
            
            
            
            39Acquisition
                  Adjustments
            
            
            230
            
            
            
            230Utility
                  Plant, Net
            
            
            7,179
            
            
            
            7,007Nonutility
                  Property and Investments:Nonutility property, net of accumulated depreciation of $77 and
                  $70
            
            
            154
            
            
            
            132Assets held in trust, net-nuclear decommissioning
            
            
            58
            
            
            
            56Other investments
            
            
            88
            
            
            
            88Nonutility Property and Investments, Net
            
            
            300
            
            
            
            276Current
                  Assets:Cash and cash equivalents
            
            
            90
            
            
            
            201Receivables, net of allowance for uncollectible accounts of $16
                  and
                  $14
            
            
            500
            
            
            
            655Receivables - affiliated companies
            
            
            29
            
            
            
            32Inventories (at average cost):Fuel
            
            
            261
            
            
            
            300Materials and supplies
            
            
            99
            
            
            
            93Emission allowances
            
            
            43
            
            
            
            22Prepayments and other
            
            
            34
            
            
            
            39Deferred income taxes
            
            
            26
            
            
            
            34Total Current Assets
            
            
            1,082
            
            
            
            1,376Deferred
                  Debits and Other Assets:Pension asset, net
            
            
            212
            
            
            
            200Emission allowances
            
            
            -
            
            
            
            27Regulatory assets
            
            
            770
            
            
            
            792Other
            
            
            119
            
            
            
            139Total Deferred Debits and Other Assets
            
            
            1,101
            
            
            
            1,158Total
            
            $
            9,662
            
            
            $
            9,817




Table
          of Contents




June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006Capitalization
                and LiabilitiesShareholders’
                  Investment:Common equity
            
            $
            2,894
            
            
            $
            2,846Preferred stock (Not subject to purchase or sinking
                  funds)
            
            
            106
            
            
            
            106Total Shareholders’ Investment
            
            
            3,000
            
            
            
            2,952Preferred
                  Stock, net (Subject to purchase or sinking funds)
            
            
            7
            
            
            
            8Long-Term
                  Debt, net
            
            
            2,959
            
            
            
            3,067Total Capitalization
            
            
            5,966
            
            
            
            6,027Current
                  Liabilities:Short-term borrowings
            
            
            509
            
            
            
            487Current portion of long-term debt
            
            
            118
            
            
            
            43Accounts payable
            
            
            281
            
            
            
            414Accounts payable - affiliated companies
            
            
            27
            
            
            
            27Customer deposits and customer prepayments
            
            
            77
            
            
            
            85Taxes accrued
            
            
            89
            
            
            
            121Interest accrued
            
            
            51
            
            
            
            51Dividends declared
            
            
            54
            
            
            
            51Other
            
            
            83
            
            
            
            126Total Current Liabilities
            
            
            1,289
            
            
            
            1,405Deferred
                  Credits and Other Liabilities:Deferred income taxes, net
            
            
            943
            
            
            
            947Deferred investment tax credits
            
            
            104
            
            
            
            120Asset retirement obligations
            
            
            300
            
            
            
            292Postretirement benefits
            
            
            197
            
            
            
            194Regulatory liabilities
            
            
            748
            
            
            
            714Other
            
            
            115
            
            
            
            118Total Deferred Credits and Other Liabilities
            
            
            2,407
            
            
            
            2,385Commitments
                  and Contingencies (Note 5)
            
            
            -
            
            
            
            -Total
            
            $
            9,662
            
            
            $
            9,817





See
      Notes
      to Condensed Consolidated Financial Statements.




Table
          of Contents


SCANA
      CORPORATION


CONDENSED
      CONSOLIDATED STATEMENTS OF
      INCOME


(Unaudited)




Three
                Months Ended
            Six
                Months EndedJune
                30,
            June
                30,Millions
                of dollars, except per share amounts
            
            2007
            
            2006
            
            2007
            
            2006Operating
                Revenues:Electric
            
            $
            470
            
            $
            461
            
            $
            913
            
            $
            859Gas - regulated
            
            
            191
            
            
            215
            
            
            627
            
            
            730Gas - nonregulated
            
            
            346
            
            
            268
            
            
            830
            
            
            744Total Operating Revenues
            
            
            1,007
            
            
            944
            
            
            2,370
            
            
            2,333Operating
                  Expenses:Fuel used in electric generation
            
            
            153
            
            
            147
            
            
            309
            
            
            264Purchased power
            
            
            7
            
            
            8
            
            
            18
            
            
            12Gas purchased for resale
            
            
            447
            
            
            403
            
            
            1,174
            
            
            1,213Other operation and maintenance
            
            
            160
            
            
            150
            
            
            334
            
            
            307Depreciation and amortization
            
            
            86
            
            
            77
            
            
            177
            
            
            153Other taxes
            
            
            38
            
            
            37
            
            
            79
            
            
            76Total Operating Expenses
            
            
            891
            
            
            822
            
            
            2,091
            
            
            2,025Operating
                  Income
            
            
            116
            
            
            122
            
            
            279
            
            
            308Other
                  Income (Expense):Other income
            
            
            18
            
            
            23
            
            
            47
            
            
            81Other expenses
            
            
            (8
            )
            
            (7
            )
            
            (26
            )
            
            (53
            )Interest
                  charges, net of allowance for borrowed fundsused during construction of  $3, $2, $5 and $3
            
            
            (51
            )
            
            (53
            )
            
            (103
            )
            
            (107
            )Gain
                  on sale of assets
            
            
            -
            
            
            -
            
            
            1
            
            
            -Preferred dividends of subsidiary
            
            
            (2
            )
            
            (2
            )
            
            (4
            )
            
            (4
            )Allowance
                  for equity funds used during construction
            
            
            1
            
            
            -
            
            
            1
            
            
            -Total Other Expense
            
            
            (42
            )
            
            (39
            )
            
            (84
            )
            
            (83
            )Income
                  Before Income Tax Expense, Losses from EquityMethod Investments and Cumulative Effect of Accounting
                  Change
            
            
            74
            
            
            83
            
            
            195
            
            
            225Income
                  Tax Expense
            
            
            17
            
            
            23
            
            
            48
            
            
            69Income
                  Before Losses from Equity MethodInvestments
                  and Cumulative Effect of Accounting Change
            
            
            57
            
            
            60
            
            
            147
            
            
            156Losses
                  from Equity Method Investments
            
            
            (2
            )
            
            (2
            )
            
            (7
            )
            
            (6
            )Cumulative
                  Effect of Accounting Change, net of taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            6Net
                  Income
            
            $
            55
            
            $
            58
            
            $
            140
            
            $
            156Basic
                  and Diluted Earnings Per Share of Common Stock:Before Cumulative Effect of Accounting Change
            
            $
            .47
            
            $
            .50
            
            $
            1.20
            
            $
            1.30Cumulative Effect of Accounting Change, net of taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            .05Basic and Diluted Earnings Per Share
            
            $
            .47
            
            $
            .50
            
            $
            1.20
            
            $
            1.35Weighted
                  Average Shares Outstanding (millions)
            
            
            116.7
            
            
            115.5
            
            
            116.7
            
            
            115.3See
                  Notes to Condensed Consolidated Financial
                  Statements.




Table
          of Contents


SCANA
      CORPORATION


CONDENSED
      CONSOLIDATED STATEMENTS OF CASH
      FLOWS


(Unaudited)


Six
                Months EndedJune
                30,Millions
                of dollars
            
            2007
            
            2006Cash
                Flows From Operating Activities:Net
                  income
            
            $
            140
            
            $
            156Adjustments
                  to reconcile net income to net cash provided from operating
                  activities:Cumulative effect of accounting change, net of taxes
            
            
            -
            
            
            (6
            )Excess losses, net of distributions from equity method
                  investments
            
            
            10
            
            
            6Depreciation and amortization
            
            
            182
            
            
            154Amortization of nuclear fuel
            
            
            9
            
            
            9Hedging
                  activities
            
            
            3
            
            
            (3
            )Carrying cost recovery
            
            
            (1
            )
            
            (4
            )Gain
                  on sale of assets
            
            
            (1
            )
            
            -Cash
                  provided (used) by changes in certain assets and
                  liabilities:Receivables, net
            
            
            158
            
            
            363Inventories
            
            
            10
            
            
            5Prepayments and other
            
            
            8
            
            
            (12
            )Pension asset
            
            
            (12
            )
            
            (7
            )Other regulatory assets
            
            
            22
            
            
            10Deferred income taxes, net
            
            
            4
            
            
            14Regulatory liabilities
            
            
            10
            
            
            22Postretirement benefits
            
            
            3
            
            
            4Accounts payable
            
            
            (112
            )
            
            (214
            )Taxes accrued
            
            
            (32
            )
            
            (25
            )Changes in fuel adjustment clauses
            
            
            (13
            )
            
            13Changes in other assets
            
            
            15
            
            
            26Changes in other liabilities
            
            
            (49
            )
            
            (42
            )Net
                  Cash Provided From Operating Activities
            
            
            354
            
            
            469Cash
                  Flows From Investing Activities:Utility
                  property additions and construction expenditures
            
            
            (312
            )
            
            (224
            )Proceeds
                  from sale of assets
            
            
            1
            
            
            18Nonutility
                  property additions
            
            
            (31
            )
            
            (21
            )Investments
            
            
            (10
            )
            
            (21
            )Net
                  Cash Used For Investing Activities
            
            
            (352
            )
            
            (248
            )Cash
                  Flows From Financing Activities:Proceeds
                  from issuance of debt
            
            
            -
            
            
            123Proceeds
                  from issuance of common stock
            
            
            -
            
            
            40Repurchase
                  of equity securities
            
            
            (4
            )
            
            -Repayment
                  of debt
            
            
            (31
            )
            
            (11
            )Dividends
            
            
            (100
            )
            
            (97
            )Short-term
                  borrowings, net
            
            
            22
            
            
            (178
            )Net
                  Cash Used For Financing Activities
            
            
            (113
            )
            
            (123
            )Net
                  Increase (Decrease) In Cash and Cash Equivalents
            
            
            (111
            )
            
            98Cash
                  and Cash Equivalents, January 1
            
            
            201
            
            
            62Cash
                  and Cash Equivalents, June 30
            
            $
            90
            
            $
            160Supplemental
                  Cash Flow Information:Cash
                  paid for  - Interest (net of capitalized interest of $5 and
                  $3)
            
            $
            104
            
            $
            107- Income taxes
            
            
            26
            
            
            38Noncash
                  Investing and Financing Activities:Accrued
                  construction expenditures
            
            
            34
            
            
            18




See
                Notes to Condensed Consolidated Financial
                Statements.




Table
          of Contents




SCANA
                CORPORATIONCONDENSED
                CONSOLIDATED STATEMENTS OF
                COMPREHENSIVE INCOME(Unaudited)Three
                Months Ended
            Six
                Months EndedJune
                30,
            June
                30,Millions
                of dollars
            
            2007
            
            2006
            
            2007
            
            2006Net
                  Income
            
            $
            55
            
            $
            58
            
            $
            140
            
            $
            156Other
                  Comprehensive Income, net of tax:Unrealized gains (losses) on hedging activities:Unrealized
                  holding gains (losses) arising during period
            
            
            (6
            )
            
            (5
            )
            
            1
            
            
            (20
            )Reclassification
                  adjustment for losses included in net income
            
            
            -
            
            
            4
            
            
            11
            
            
            17Total
                  Comprehensive Income (1)
            
            $
            49
            
            $
            57
            
            $
            152
            
            $
            153(1)
                  Accumulated
                  other comprehensive loss totaled $16.9 million as of June 30, 2007
                  and
                  $29.2 million as ofDecember
                  31, 2006.See
                  Notes to Condensed Consolidated Financial
                  Statements.





Table
          of Contents


SCANA
      CORPORATION


NOTES
      TO CONDENSED CONSOLIDATED FINANCIAL
      STATEMENTS


June
      30,
      2007


(Unaudited)





The
      following notes should be read in conjunction with the Notes to Consolidated
      Financial Statements appearing in SCANA Corporation’s (SCANA and, together with
      its consolidated subsidiaries, the Company) Annual Report on Form 10-K for
      the
      year ended December 31, 2006. These are interim financial statements, and due
      to
      the seasonality of the Company’s business and matters that may occur during the
      rest of the year, the amounts reported in the Condensed Consolidated Statements
      of Income are not necessarily indicative of amounts expected for the full year.
      In the opinion of management, the information furnished herein reflects all
      adjustments, all of a normal recurring nature, which are necessary for a fair
      statement of the results for the interim periods reported.





1.                SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES





A.                Basis
      of Accounting





The
      Company accounts for its regulated utility operations, assets and liabilities
      in
      accordance with the provisions of Statement of Financial Accounting Standards
      (SFAS) 71, *“Accounting for the Effects of Certain Types of Regulation.”*SFAS 71 requires cost-based rate-regulated utilities to recognize in
      their financial statements certain revenues and expenses in different time
      periods than do enterprises that are not rate-regulated. As a result, the
      Company has recorded the regulatory assets and regulatory liabilities summarized
      as follows.





June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006Regulatory
                  Assets:Accumulated
                  deferred income taxes
            
            $
            174
            
            
            $
            174Under-collections
                  - electric fuel and gas cost adjustment clauses
            
            
            81
            
            
            
            95Deferred
                  purchased power costs
            
            
            4
            
            
            
            9Environmental
                  remediation costs
            
            
            28
            
            
            
            29Asset
                  retirement obligations and related funding
            
            
            271
            
            
            
            264Franchise
                  agreements
            
            
            52
            
            
            
            55Deferred
                  regional transmission organization costs
            
            
            7
            
            
            
            8Deferred
                  employee benefit plan costs
            
            
            138
            
            
            
            142Other
            
            
            15
            
            
            
            16Total
                  Regulatory Assets
            
            $
            770
            
            
            $
            792





Regulatory
                  Liabilities:Accumulated
                  deferred income taxes
            
            $
            36
            
            
            $
            38Over-collections
                  - electric fuel and gas cost adjustment clauses
            
            
            15
            
            
            
            8Other
                  asset removal costs
            
            
            621
            
            
            
            599Storm
                  damage reserve
            
            
            47
            
            
            
            44Planned
                  major maintenance
            
            
            9
            
            
            
            6Other
            
            
            20
            
            
            
            19Total
                  Regulatory Liabilities
            
            $
            748
            
            
            $
            714





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





Under-
      and over-collections-electric fuel and gas cost adjustment clauses, net,
      represent amounts under- or over-collected from customers pursuant to the fuel
      adjustment clause (electric customers) or gas cost adjustment clause (gas
      customers) as approved by the Public Service Commission of South Carolina
      (SCPSC) or the North Carolina Utilities Commission (NCUC) during annual
      hearings. Included in these amounts are regulatory assets or liabilities arising
      from realized and unrealized gains and losses incurred in the natural gas
      hedging programs of the Company’s regulated operations.




Deferred
      purchased power costs represent costs necessitated by outages at two of South
      Carolina Electric & Gas Company’s (SCE&G) base load generating plants in
      winter 2000-2001. The SCPSC approved recovery of these costs in base rates
      over
      a three-year period beginning January 2005.


Table
          of Contents




Environmental
      remediation costs represent costs associated with the assessment and clean-up
      of
      manufactured gas plant (MGP) sites currently or formerly owned by the
      Company. Costs incurred at sites owned by SCE&G are being recovered
      through rates, of which $17.2 million remain to be recovered. SCE&G is
      authorized to amortize $1.4 million of these costs on an annual
      basis.  Costs incurred through June 30, 2006, at sites owned by Public
      Service Company of North Carolina, Incorporated (PSNC Energy) are being
      recovered through rates over a three-year period. In addition, management
      believes that costs incurred subsequent to June 30, 2006, totaling $2.3 million
      at June 30, 2007, and the estimated remaining costs to be incurred of $5.4
      million, will be recoverable by PSNC Energy through rates.




Asset
      retirement obligations (ARO) and related funding represents the regulatory
      asset
      associated with the legal obligation to decommission and dismantle V. C. Summer
      Nuclear Station (Summer Station) and conditional AROs recorded as required
      by
      SFAS 143, *“Accounting for Asset Retirement Obligations,”*and Financial
      Accounting Standards Board Interpretation (FIN) 47, *“Accounting for
      Conditional Asset Retirement Obligations.”*





Franchise
      agreements represent costs associated with electric and gas franchise agreements
      with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC
      order, SCE&G began amortizing these amounts through cost of service rates in
      February 2003 over approximately 20 years.





Deferred
      regional transmission organization costs represent costs incurred by SCE&G
      in the United States Federal Energy Regulatory Commission (FERC)-mandated
      formation of GridSouth. The project was suspended in 2002. Effective January
      2005, the SCPSC approved the amortization of these amounts through cost of
      service rates over five years.





Deferred
      employee benefit plan costs
      represent pension and other postretirement benefit costs which were accrued
      as
      liabilities under provision of SFAS 158, *“Employe**r**s’
Accounting for Defined Benefit Pension and Other Postretirement
      Plans,”***but which are expected to be recovered through
      utility rates.





Other
      asset removal costs represent net collections through depreciation rates of
      estimated costs to be incurred for the future removal of assets.





The
      storm
      damage reserve represents an SCPSC-approved collection through SCE&G
      electric rates, capped at $50 million, which can be applied to offset
      incremental storm damage costs in excess of $2.5 million in a calendar year.
      For
      the six months ended June 30, 2007, no amounts were drawn from this
      reserve.





Planned
      major maintenance related to certain fossil hydro turbine/generation
      equipment and nuclear refueling outages is accrued in advance of the time the
      costs are incurred, as approved through specific SCPSC orders. SCE&G is
      allowed to collect $8.5 million annually over an eight-year period, beginning
      in
      January 2005, through electric rates to offset turbine maintenance expenditures.
      Nuclear refueling charges are accrued during each 18-month refueling outage
      cycle as a component of cost of service.





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





B.       Earnings
      Per Share





In
      accordance with SFAS 128, *“Earnings Per Share,”* the Company
      computes basic earnings per share by dividing net income by the weighted average
      number of common shares outstanding for the period. The Company computes diluted
      earnings per share using this same formula, after giving effect to securities
      considered to be dilutive potential common stock. The Company uses the treasury
      stock method in determining total dilutive potential common stock. The Company
      has issued no securities that would have an antidilutive effect on earnings
      per
      share.





C.       Affiliated Transactions





SCE&G
      holds equity-method investments in two partnerships involved in converting
      coal
      to synthetic fuel. SCE&G’s receivables from these affiliated companies were
      $28.4 million at June 30, 2007 and $31.8 million at December 31, 2006. 
SCE&G’s payables to these affiliated companies were $26.6 million at June
      30, 2007 and $26.6 million at December 31, 2006.  Table
            of Contents


SCE&G
      purchases shaft horsepower
      from a cogeneration facility.  The facility is owned by a limited
      liability company (LLC) in which SCANA holds an equity-method
      investment.  SCE&G’s payables to the LLC were $2.4 million at June
      30, 2007 and $2.5 million at December 31, 2006.  SCE&G purchased
      $6.1 million and $13.4 million of shaft horsepower from the LLC for the three
      and six months ended June 30, 2007, respectively, and purchased $6.4 million
      and
      $12.7 million of shaft horsepower from the LLC for the three and six months
      ended June 30, 2006, respectively.





D.     
      Pension and Other Postretirement Benefit Plans





Components
      of net periodic benefit income or cost recorded by the Company were as
      follows:





Pension
                Benefits
            
            Other
                Postretirement BenefitsThree
                months ended June 30,
            
            2007
            
            2006
            
            2007
            
            2006Millions
                  of dollarsService
                  cost
            
            $
            3.5
            
            $
            3.5
            
            $
            1.2
            
            $
            1.2Interest
                  cost
            
            
            10.4
            
            
            9.9
            
            
            3.0
            
            
            2.8Expected
                  return on assets
            
            
            (20.1
            )
            
            (18.8
            )
            
            -
            
            
            -Prior
                  service cost amortization
            
            
            1.7
            
            
            1.7
            
            
            0.3
            
            
            0.2Transition
                  obligation amortization
            
            
            -
            
            
            0.1
            
            
            0.2
            
            
            0.2Amortization
                  of actuarial loss
            
            
            -
            
            
            0.2
            
            
            0.3
            
            
            0.4Net
                  periodic benefit (income) cost
            
            $
            (4.5
            )
            $
            (3.4
            )
            $
            5.0
            
            $
            4.8





Pension
                Benefits
            
            Other
                Postretirement BenefitsSix
                months ended June 30,
            
            2007
            
            2006
            
            2007
            
            2006Millions
                  of dollarsService
                  cost
            
            $
            7.0
            
            $
            7.0
            
            $
            2.4
            
            $
            2.4Interest
                  cost
            
            
            20.7
            
            
            19.8
            
            
            6.0
            
            
            5.6Expected
                  return on assets
            
            
            (40.2
            )
            
            (37.6
            )
            
            -
            
            
            -Prior
                  service cost amortization
            
            
            3.4
            
            
            3.4
            
            
            0.6
            
            
            0.4Transition
                  obligation amortization
            
            
            -
            
            
            0.2
            
            
            0.4
            
            
            0.4Amortization
                  of actuarial loss
            
            
            -
            
            
            0.4
            
            
            0.6
            
            
            0.7Net
                  periodic benefit (income) cost
            
            $
            (9.1
            )
            $
            (6.8
            )
            $
            10.0
            
            $
            9.5





E.      New
      Accounting Matters





SFAS
      159,
*“The Fair Value Option for Financial Assets and Financial Liabilities,”*
      was issued in February 2007. SFAS 159 allows entities to measure at fair value
      many financial instruments and certain other assets and liabilities that are
      not
      otherwise required to be measured at fair value. SFAS 159 is effective for
      fiscal years beginning after November 15, 2007. The Company has not determined
      what impact, if any, that adoption will have on the Company’s results of
      operations, cash flows or financial position.





SFAS
      157,
*“Fair Value Measurements,”* was issued in September 2006.  SFAS 157
      establishes a framework for measuring fair value to increase the consistency
      and
      comparability in fair value measurements.  The Company will adopt SFAS 157
      in the first quarter of 2008, and has not determined what impact, if any, the
      adoption will have on the Company’s results of operations, cash flows or
      financial position.





FIN
      48,
“*Accounting for Uncertainty in Income Taxes,”*clarifies the accounting
      for uncertainty in income taxes recognized in an enterprise’s financial
      statements in accordance with SFAS 109,*“Accounting for Income
      Taxes.”*****FIN 48 prescribes financial statement
      recognition threshold and measurement attributes for tax positions taken or
      expected to be taken in  tax returns. FIN 48 also provides guidance on
      derecognition, classification, interest and penalties, accounting in interim
      periods, disclosure and transition.  The Company adopted FIN 48 in the
      first quarter of 2007.  The impact on the Company’s results of
      operations, cash flows or financial position is discussed at Note
      1F.





FASB
      Staff Position (FSP) AUG AIR-1 *“Accounting for Planned Major Maintenance
      Activities,”* amended APB 28, “*Interim Financial Reporting,*” to
      prohibit the use of the accrue-in-advance method of accounting for planned
      major
      maintenance.  As disclosed in Note 1A, SCE&G has received specific
      SCPSC orders providing for use of accrue-in-advance accounting for certain
      planned major maintenance activities. Accordingly, SCE&G will continue to
      follow accrue-in-advance accounting as allowed under SFAS 71 for these
      activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007
      had no impact on the Company’s results of operations, cash flows or financial
      position.


Table
          of Contents


F.      Income
      Taxes





The
      Company files a consolidated federal income tax return and the Company and
      its
      subsidiaries file various applicable state and local income tax
      returns.  The Internal Revenue Service (IRS) has completed
      examinations of the Company’s federal returns through 2004, and the Company’s
      federal returns through 2001 are closed for additional assessment.  On
      July 30, 2007, the statute of limitations for the 2002 federal return expired,
      but no material changes resulted.  With a few exceptions, the Company
      is no longer subject to state and local income tax examinations by tax
      authorities for years before 2003.  The IRS has completed the
      examination of S. C. Coaltech No. 1 LP., a synthetic fuel partnership in which
      the Company has an interest, for the 2004 tax year.  The Company does
      not anticipate that any adjustments from the examination will have a material
      impact on the earnings, cash flows or the financial position of the
      Company.  The Company continues to believe that all of its synthetic
      fuel tax credits have been properly claimed.





In
      connection with the initial adoption of FIN 48 effective January 1, 2007, the
      Company removed $15 million of previously recognized tax benefits from its
      balance sheet.  Because regulatory liabilities had been recorded for
      these previously recognized tax benefits under the provisions of SFAS 71, these
      benefits had never been recognized in the Company’s earnings or retained
      earnings.  As a result, the initial adoption of FIN 48 had no effect
      on the Company’s equity.  The total amount of unrecognized tax
      benefits that, if recognized, would affect the effective tax rate is $15
      million.  Because the benefits would be amortized into earnings over a
      number of years under SFAS 71, the impact on any individual year’s effective tax
      rate would be immaterial.  No material changes in the status of our
      tax positions have occurred subsequent to adoption.





The
      Company recognizes interest accrued related to unrecognized tax benefits within
      interest expense and recognizes tax penalties within other
      expenses.  Through June 30, 2007, the Company has not accrued any
      significant amount of interest or tax penalties.





2.       RATE
      AND OTHER REGULATORY MATTERS




*SCE&G*





Electric




On
      June
      15, 2007 SCE&G filed an application with the SCPSC requesting a 6.75%
      increase in retail electric rates.  The application, among other
      things, seeks recovery of costs incurred to perform mandatory environmental
      upgrades to SCE&G’s generating plants.  SCE&G’s application is
      expected to be heard by the SCPSC in November 2007.  If approved, the
      new rates would be effective in January 2008.





SCE&G's
      rates are established using a cost of fuel component approved by the SCPSC
      which
      may be modified periodically to reflect changes in the price of fuel purchased
      by SCE&G. In May 2006 SCE&G agreed to spread the recovery of
      previously under-collected fuel costs of $38.5 million over a two-year
      period.





Gas





On
      June
      15, 2007 SCE&G filed an application with the SCPSC requesting an increase in
      retail natural gas rates of 1.3%  under the terms of the Natural Gas
      Rate Stabilization Act (Stabilization Act).  The Stabilization Act is
      designed to reduce the volatility of costs charged to customers by allowing
      for
      more timely recovery of the costs that regulated utilities incur related to
      natural gas service infrastructure.  The SCPSC is expected to review
      SCE&G’s filing in October 2007.  If approved, the rate adjustment
      would be implemented with the first billing cycle in November 2007.





In
      September 2006, the SCPSC approved an increase in retail natural gas rates
      of
      3.2% under the terms of the Stabilization Act.  The rate adjustment was
      effective with the first billing cycle in November 2006.





SCE&G's
      rates are established using a cost of gas component approved by the SCPSC in
      October 2006 which authorized SCE&G to adjust its cost of gas on a monthly,
      rather than an annual, basis beginning in December 2006.   The
      cost of gas adjustment is based on a twelve-month rolling average.





*PSNC
      Energy*





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




In
      June 2007, PSNC Energy filed
      testimony in the 2007 Annual Prudence Review related to the 12 months ended
      March 31, 2007.  The NCUC will hold a hearing in August 2007 to
      consider the filing.





In
      May
      2007 the NCUC approved PSNC Energy’s request to eliminate the use of its current
      dual residential customer rate structure and replace it with a single
      residential rate.   The NCUC also ordered that PSNC Energy establish a
      new residential rate structure by November 1, 2007.  Accordingly, in
      July 2007, PSNC Energy filed a petition requesting NCUC approval to implement
      a
      residential service rate which has a winter/summer differential of 6 cents
      per
      therm.  The higher winter rate would help recover costs associated
      with operating the system during high customer demand.  If approved,
      all residential customers will be charged this rate effective November 1,
      2007.  These changes in the rate structure will have no impact on 2007
      earnings.





In
      October 2006, the NCUC granted PSNC Energy an annual increase in retail natural
      gas margin revenues of approximately $15.2 million, or 2.6 percent, which was
      offset by a $9.2 million decrease in fixed-gas cost revenues, for an overall
      increase of $6.0 million, or 1.0 percent. The new rates are based on an allowed
      overall rate of return of 8.9 percent, and became effective for services
      rendered on or after November 1, 2006. In connection with the rate
      increase, the NCUC approved PSNC Energy’s recovery through rates, over a
      three-year period, of certain costs for environmental remediation and pipeline
      integrity management.





3.      
      LONG-TERM DEBT





On
      February 15, 2007 SCANA redeemed at maturity $25 million of its medium-term
      notes which bore interest at 6.9%.





Substantially
      all of SCE&G’s and South Carolina Generating Company, Inc.’s (GENCO)
      electric utility plant is pledged as collateral in connection with long-term
      debt.





4.       FINANCIAL
      INSTRUMENTS





The
      Company utilizes various financial derivatives, including those designated
      as
      cash flow hedges related to natural gas. The Company also utilizes swap
      agreements to manage interest rate risk. These transactions are more fully
      described in Note 9 to the consolidated financial statements in SCANA’s Annual
      Report on Form 10-K for the year ended December 31, 2006.




At
      June
      30, 2007 the estimated fair value of PSNC Energy’s interest rate swaps totaled
      less than $0.1 million (gain) related to combined notional amounts of $16.0
      million.





The
      Company’s regulated gas operations
      (SCE&G and PSNC Energy) hedge natural gas purchasing activities using
      over-the-counter options and swaps and New York Mercantile Exchange (NYMEX)
      futures and options. SCE&G’s tariffs include a purchased gas adjustment
      (PGA) clause that provides for the recovery of actual gas costs incurred. The
      SCPSC has ruled that the results of these hedging activities are to be included
      in the PGA. As such, costs of related derivatives utilized to hedge gas
      purchasing activities are recoverable through the weighted average cost of
      gas
      calculation. The offset to the change in fair value of these derivatives is
      recorded as a regulatory asset or liability. PSNC Energy's tariffs also include
      a provision for the recovery of actual gas costs incurred. PSNC Energy records
      premiums, transaction fees, margin requirements and any realized and unrealized
      gains or losses from its hedging program in deferred accounts as a regulatory
      asset or liability for the over- or under-recovery of gas costs.





The
      Company’s nonregulated gas
      operations recognize gains and losses as a result of qualifying cash flow hedges
      whose hedged transactions occur during the reporting period and record them,
      net
      of taxes, in cost of gas. The effects of gains or losses resulting from these
      hedging activities are either offset by the recording of the related hedged
      transactions or are included in gas sales pricing decisions made by the business
      unit.  The Company estimates that most of the June 30, 2007 unrealized loss
      balance of $5.9 million, net of taxes, will be reclassified from accumulated
      other comprehensive income (loss) to earnings within the next twelve months
      as
      an increase to gas cost if market prices remain at current levels. As of June
      30, 2007, all of the Company's cash flow hedges settle by their terms before
      the
      end of 2010.





PSNC
      Energy utilizes asset management
      and supply service agreements with counterparties for certain of its natural
      gas
      storage facilities.  At June 30, 2007, such counterparties held 45% of PSNC
      Energy’s natural gas inventory, with a carrying value of $30.7 million, through
      either capacity release or agency relationships.  Under the terms of
      the asset management agreements, PSNC Energy receives storage asset management
      fees and, in certain instances, a share of profits.  No fees are received
      under supply service agreements.  The agreements expire at various times
      through March 31, 2009.


Table
          of Contents


5.       COMMITMENTS
      AND CONTINGENCIES





Reference
      is made to Note 10 to the
      consolidated financial statements appearing in SCANA’s Annual Report on Form
      10-K for the year ended December 31, 2006. Commitments and contingencies at
      June
      30, 2007 include the following:





A.      Nuclear
      Insurance





The
      Price-Anderson Indemnification Act deals with public liability for a nuclear
      incident and establishes the liability limit for third-party claims associated
      with any nuclear incident at $10.5 billion. Each reactor licensee is
      currently liable for up to $100.6 million per reactor owned for each
      nuclear incident occurring at any reactor in the United States, provided that
      not more than $15 million of the liability per reactor would be assessed
      per year. SCE&G's maximum assessment, based on its two-thirds ownership of
      Summer Station, would be $67.1 million per incident, but not more than
      $10 million per year.





SCE&G
      currently maintains policies (for itself and on behalf of Santee Cooper, the
      one-third owner of Summer Station) with Nuclear Electric Insurance Limited.
      The
      policies, covering the nuclear facility for property damage, excess property
      damage and outage costs, permit retrospective assessments under certain
      conditions to cover insurer's losses. Based on the current annual premium,
      SCE&G's portion of the retrospective premium assessment would not exceed
      $14.1 million.





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





B.     
      Environmental





*SCE&G*





In
      March
      2005, the United States Environmental Protection Agency (EPA) issued a final
      rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District
      of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide
      and sulfur dioxide emissions in order to attain mandated state levels. SCE&G
      has petitioned the United States Court of Appeals for the District of Columbia
      Circuit to review CAIR. Several other electric utilities have filed separate
      petitions. The petitioners seek a change in the method CAIR uses to allocate
      sulfur dioxide emission allowances to a method the petitioners believe is more
      equitable. The Company believes that installation of additional air quality
      controls will be needed to meet the CAIR requirements, although compliance
      plans and cost to comply with the rule have not been determined. Such costs
      will
      be material and are expected to be recoverable through rates.





In
      March
      2005, the EPA issued a final rule establishing a mercury emissions cap and
      trade
      program for coal-fired power plants that requires limits to be met in two
      phases, in 2010 and 2018. Although the Company expects to be able to meet
      the  Phase I limits through those measures it already will be taking to
      meet its CAIR obligations, it is uncertain as to how the Phase II limits will
      be
      met. Assuming Phase II limits remain unchanged, installation of additional
      air
      quality controls likely will be required to comply with the rule’s Phase II
      mercury emission caps. Final compliance plans and costs to comply with the
      rule
      are still under review. Such costs will be material and are expected to be
      recoverable through rates.





SCE&G
      has been named, along with 53 others, by the EPA as a potentially responsible
      party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located
      in Augusta, Georgia.  The EPA placed the site on the National Priorities
      List on April 19, 2006. AER conducted hazardous waste storage and treatment
      operations from 1975 to 2000, when the site was abandoned.  While
      operational, AER processed fuels from waste oils, treated industrial coolants
      and oil/water emulsions, recycled solvents and blended hazardous waste
      fuels.  During that time, SCE&G occasionally used AER for the
      processing of waste solvents, oily rags and oily wastewater. The EPA and the
      State of Georgia have documented that a release or releases have occurred at
      the
      site leading to contamination of groundwater, surface water and soils.  The
      EPA and the State of Georgia have conducted a preliminary assessment and site
      inspection. The site has not been remediated nor has a clean-up cost been
      estimated.  Although a basis for the allocation of clean-up costs among the
      PRPs is unclear, SCE&G does not believe that its involvement at this site
      would result in an allocation of costs that would have a material adverse impact
      on its results of operations, cash flows or financial condition. Any cost
      allocated to SCE&G arising from the remediation of this site, net of
      insurance recoveries, if any, is expected to be recoverable through
      rates.


Table
          of Contents





SCE&G
      has been named, along with 29 others, by the EPA as a PRP at the Carolina
      Transformer Superfund site located in Fayetteville, North Carolina.  The
      Carolina Transformer Company (CTC) conducted an electrical transformer
      rebuilding and repair operation at the site from approximately 1959 to
      1986.  During that time, SCE&G occasionally used CTC for the repair of
      existing transformers, purchase of new transformers and sale of used
      transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated
      soil and groundwater at the site.  The EPA reports that it has spent $36
      million to date.  SCE&G does not believe that its involvement at this
      site would result in an allocation of costs that would have a material adverse
      impact on its results of operations, cash flows or financial condition. Any
      cost
      allocated to SCE&G arising from the remediation of this site, net of
      insurance recoveries, if any, is expected to be recoverable through
      rates.





SCE&G
      maintains an environmental assessment program to identify and evaluate its
      current and former MGP sites that could require environmental clean-up. As
      site
      assessments are initiated, estimates are made of the amount of expenditures,
      if
      any, deemed necessary to investigate and remediate each site. These estimates
      are refined as additional information becomes available; therefore, actual
      expenditures could differ significantly from the original estimates. Amounts
      estimated and accrued to date for site assessments and clean-up relate solely
      to
      regulated operations. SCE&G defers site assessment and clean-up costs
      and recovers them through rates (see Note 1). Deferred amounts, net of amounts
      previously recovered through rates and insurance settlements, totaled $17.2
      million at June 30, 2007. The deferral includes the estimated costs associated
      with the following matters.





SCE&G
      owns
      a decommissioned MGP site in the Calhoun Park area of Charleston, South
      Carolina. SCE&G anticipates that remediation for contamination at the site
      will be completed in late 2007, with certain monitoring and retreatment
      activities continuing through 2012. As of June 30, 2007, SCE&G had spent
      $22.3 million to remediate the site and expects to spend an additional $1.0
      million prior to entering a monitoring and reporting stage. In addition, the
      National Park Service of the Department of the Interior made an initial demand
      to SCE&G for payment of $9.1 million for certain costs and damages relating
      to this site. SCE&G expects to recover any cost arising from the remediation
      of this site through rates.





SCE&G
      owns three other decommissioned MGP sites in South Carolina which contain
      residues of by-product chemicals. One of the sites has been remediated and
      will
      undergo routine monitoring until released by the South Carolina Department
      of
      Health and Environmental Control (DHEC). The other sites are currently being
      investigated under work plans approved by DHEC. SCE&G anticipates that major
      remediation activities for the three sites will be completed by 2011. As of
      June 30, 2007, SCE&G has spent $4.8 million related to these three
      sites, and expects to spend an additional $11.2 million. SCE&G expects to
      recover any cost arising from the remediation of these sites through
      rates.





*PSNC
      Energy*





PSNC
      Energy is responsible for environmental clean-up at five sites in North Carolina
      on which MGP residuals are present or suspected. PSNC Energy's actual
      remediation costs for these sites will depend on a number of factors, such
      as
      actual site conditions, third-party claims and recoveries from other PRPs.
      PSNC
      Energy has recorded a liability and associated regulatory asset of
      $5.4 million, which reflects its estimated remaining liability at
      June 30, 2007. PSNC Energy expects to recover any cost allocable to PSNC
      Energy arising from the remediation of these sites through rates.





C.     
      Claims and Litigation





In
      August
      2003, SCE&G was served as a co-defendant in a purported class action lawsuit
      styled as Collins v. Duke Energy Corporation, Progress Energy Services Company,
      and South Carolina Electric & Gas Company in South Carolina's Circuit
      Court of Common Pleas for the Fifth Judicial Circuit.  The plaintiffs
      subsequently dismissed defendants Duke Energy and Progress Energy and proceeded
      against SCE&G only. The plaintiffs sought damages for the alleged improper
      use of electric transmission and distribution easements but did not assert
      a
      dollar amount for their claims. Specifically, the plaintiffs alledged that
      the
      licensing of attachments on electric utility poles, towers and other facilities
      to nonutility third parties or telecommunication companies for other than the
      electric utility’s internal use along the electric transmission and distribution
      line rights-of-way constituted a trespass. On July 20, 2007, Plaintiffs’ counsel
      filed a Stipulation of Dismissal Without Prejudice with the Lexington County
      Clerk of Court’s Office.  This case can be re-filed; however, SCANA
      and SCE&G believe that the resolution of these claims will not have a
      material adverse impact on their results of operations, cash flows or financial
      condition.





In
      May 2004, SCANA and SCE&G were served with a purported class action
      lawsuit styled as Douglas E. Gressette, individually and on behalf of other
      persons similarly situated v. South Carolina Electric & Gas Company and
      SCANA Corporation. The case was filed in South Carolina's Circuit Court of
      Common Pleas for the Ninth Judicial Circuit. The plaintiff alleges that SCANA
      and SCE&G made improper use of certain easements and rights-of-way by
      allowing fiber optic communication lines and/or wireless communication equipment
      to transmit communications other than SCANA’s and SCE&G’s
      electricity-related internal communications. The plaintiff asserted causes
      of
      action for unjust enrichment, trespass, injunction and declaratory judgment.
      The
      plaintiff did not assert a specific dollar amount for the claims. SCANA and
      SCE&G believe their actions are consistent with governing law and the
      applicable documents granting easements and rights-of-way. The Circuit Court
      granted SCANA’s and SCE&G’s motion to dismiss and issued an order dismissing
      the case in June 2005. The plaintiff appealed to the South Carolina Supreme
      Court. The Supreme Court overruled the Circuit Court in October 2006 and
      returned the case to the Circuit Court for further consideration.  In
      July 2007, the Circuit Court issued a ruling that limits the plaintiff’s
      purported class to owners of easements situated in Charleston County, South
      Carolina.  The plaintiff has appealed this ruling to the South
      Carolina Court of Appeals.  It is anticipated that this case may not
      go to trial before 2008.  SCANA and SCE&G will continue to mount a
      vigorous defense and believe that the resolution of these claims will not have
      a
      material adverse impact on their results of operations, cash flows or financial
      condition.





A
      complaint was filed in October 2003 against SCE&G by the State of South
      Carolina alleging that SCE&G violated the Unfair Trade Practices Act by
      charging municipal franchise fees to some customers residing outside a
      municipality's limits. The complaint sought restitution to all affected
      customers and penalties of up to $5,000 for each separate violation. The claim
      against SCE&G has been settled by an agreement between the parties, and the
      settlement has been approved by South Carolina’s Circuit Court of Common Pleas
      for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the
      SCPSC in October 2003 pursuant to S. C. Code Ann. R.103-836. The petition
      requests that the SCPSC exercise its jurisdiction to investigate the operation
      of the municipal franchise fee collection requirements applicable to SCE&G’s
      electric and gas service, to approve SCE&G’s efforts to correct any past
      franchise fee billing errors, to adopt improvements in the system which will
      reduce such errors in the future, and to adopt any regulation that the SCPSC
      deems just and proper to regulate the franchise fee collection process. A
      hearing on this petition has not been scheduled. The Company believes that
      the
      resolution of these matters will not have a material adverse impact on its
      results of operations, cash flows or financial condition.





The
      Company is also engaged in various other claims and litigation incidental to
      its
      business operations which management anticipates will be resolved without a
      material adverse impact on the Company’s results of operations, cash flows or
      financial condition.





6.
            SEGMENT
                OF BUSINESS INFORMATION





The
      Company’s reportable segments are listed in the following table. The Company
      uses operating income to measure profitability for its regulated operations;
      therefore, net income is not allocated to the Electric Operations, Gas
      Distribution and Gas Transmission segments. The Company uses net income to
      measure profitability for its Retail Gas Marketing and Energy Marketing
      segments. Gas Distribution is comprised of the local distribution operations
      of
      SCE&G and PSNC Energy which meet SFAS 131 criteria for aggregation. All
      Other includes equity method investments and other nonreportable
      segments.





Gas
      Transmission is comprised of Carolina Gas Transmission Corporation (CGTC) which,
      effective November 1, 2006, began operating as an open access,
      transportation-only interstate pipeline company regulated by
      FERC.  For prior periods, Gas Transmission was comprised of South
      Carolina Pipeline Corporation (SCPC).  Effective November 1, 2006, SCG
      Pipeline, Inc. (SCG Pipeline) (previously reported in All Other) was merged
      into
      SCPC and the company’s name was changed to CGTC.  Prior to the merger,
      SCPC purchased, transported and sold natural gas intrastate and SCG Pipeline
      transported natural gas interstate.  The results of CGTC, SCPC and SCG
      Pipeline appear in the Gas Transmission segment for all periods
      presented.





External
            Intersegment
            Operating
            Net
            SegmentMillions
                of dollars
            Revenue
            Revenue
            Income
                (Loss)
            Income
                (Loss)
            Assets*Three
                  Months Ended June 30, 2007*Electric
                  Operations
            
            $
            470
            
            $
            2
            
            $
            110
            
            
            n/aGas
                  Distribution
            
            
            189
            
            
            -
            
            
            (1
            )
            
            n/aGas
                  Transmission
            
            
            2
            
            
            9
            
            
            4
            
            
            n/aRetail
                  Gas Marketing
            
            
            102
            
            
            -
            
            
            n/a
            
            $
            2Energy
                  Marketing
            
            
            244
            
            
            47
            
            
            n/a
            
            
            1All
                  Other
            
            
            (6
            )
            
            83
            
            
            n/a
            
            
            (5
            )Adjustments/Eliminations
            
            
            6
            
            
            (141
            )
            
            3
            
            
            57Consolidated
                  Total
            
            $
            1,007
            
            $
            -
            
            $
            116
            
            $
            55





*Six
                  Months Ended June 30, 2007*Electric
                  Operations
            
            $
            913
            
            $
            4
            
            $
            166
            
            
            n/a
            
            $
            5,746Gas
                  Distribution
            
            
            622
            
            
            -
            
            
            73
            
            
            n/a
            
            
            1,801Gas
                  Transmission
            
            
            5
            
            
            20
            
            
            9
            
            
            n/a
            
            
            285Retail
                  Gas Marketing
            
            
            343
            
            
            -
            
            
            n/a
            
            $
            20
            
            
            140Energy
                  Marketing
            
            
            487
            
            
            112
            
            
            n/a
            
            
            1
            
            
            121All
                  Other
            
            
            12
            
            
            168
            
            
            n/a
            
            
            (9
            )
            
            550Adjustments/Eliminations
            
            
            (12
            )
            
            (304
            )
            
            31
            
            
            128
            
            
            1,019Consolidated
                  Total
            
            $
            2,370
            
            $
            -
            
            $
            279
            
            $
            140
            
            $
            9,662




Table
          of Contents





External
            Intersegment
            Operating
            Net
            SegmentMillions
                of dollars
            Revenue
            Revenue
            Income
                (Loss)
            Income
                (Loss)
            Assets*Three
                  Months Ended June 30, 2006*Electric
                  Operations
            
            $
            461
            
            $
            3
            
            $
            119
            
            
            n/aGas
                  Distribution
            
            
            165
            
            
            -
            
            
            (7
            )
            
            n/aGas
                  Transmission
            
            
            50
            
            
            74
            
            
            9
            
            
            n/aRetail
                  Gas Marketing
            
            
            91
            
            
            -
            
            
            n/a
            
            $
            3Energy
                  Marketing
            
            
            177
            
            
            20
            
            
            n/a
            
            
            (1
            )All
                  Other
            
            
            13
            
            
            77
            
            
            n/a
            
            
            1Adjustments/Eliminations
            
            
            (13
            )
            
            (174
            )
            
            1
            
            
            55Consolidated
                  Total
            
            $
            944
            
            $
            -
            
            $
            122
            
            $
            58





*Six
                  Months Ended June 30, 2006*Electric
                  Operations
            
            $
            859
            
            $
            4
            
            $
            210
            
            
            n/a
            
            $
            5,458Gas
                  Distribution
            
            
            611
            
            
            -
            
            
            54
            
            
            n/a
            
            
            1,648Gas
                  Transmission
            
            
            119
            
            
            229
            
            
            18
            
            
            n/a
            
            
            363Retail
                  Gas Marketing
            
            
            362
            
            
            -
            
            
            n/a
            
            $
            24
            
            
            151Energy
                  Marketing
            
            
            382
            
            
            31
            
            
            n/a
            
            
            (1)
            
            
            91All
                  Other
            
            
            29
            
            
            150
            
            
            n/a
            
            
            (3)
            
            
            514Adjustments/Eliminations
            
            
            (29)
            
            
            (414)
            
            
            26
            
            
            136
            
            
            1,173Consolidated
                  Total
            
            $
            2,333
            
            $
            -
            
            $
            308
            
            $
            156
            
            $
            9,398


Table
          of Contents


**ITEM
      2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF
      FINANCIAL CONDITION AND**


**RESULTS OF OPERATIONS**





**SCANA
      CORPORATION**





The
      following discussion should be read in conjunction with Management’s Discussion
      and Analysis of Financial Condition and Results of Operations appearing in
      SCANA
      Corporation’s (SCANA, and together with its consolidated subsidiaries, the
      Company) Annual Report on Form 10-K for the year ended December 31,
      2006.





**RESULTS
      OF OPERATIONS**


**FOR
                THE THREE AND SIX MONTHS ENDED JUNE 30,
                2007**


**AS
      COMPARED TO THE CORRESPONDING PERIODS IN 2006**





**Earnings
      Per Share**




The
      Company's earnings are reported in accordance with generally accepted accounting
      principles (GAAP). Management believes that, in addition to reported earnings
      under GAAP, the Company's GAAP-adjusted net earnings from operations provides
      a
      meaningful representation of its fundamental earnings power and can aid in
      performing period-over-period financial analysis and comparison with peer group
      data. In management's opinion, GAAP-adjusted net earnings from operations is
      a
      useful indicator of the financial results of the Company's primary businesses.
      This measure is also a basis for management's provision of earnings guidance
      and
      growth projections, and it is used by management in making resource allocation
      and other budgetary and operational decisions. This non-GAAP performance measure
      is not intended to replace the GAAP measure of net earnings, but is offered
      as a
      supplement to it. A reconciliation of reported (GAAP) earnings per share to
      GAAP-adjusted net earnings from operations per share is provided in the table
      below:





Second
                Quarter
            Year
                to Date2007
            
            2006
            
            2007
            
            2006Reported
                  (GAAP) earnings per share:
            
            $
            .47
            
            $
            .50
            
            $
            1.20
            
            $
            1.35Deduct:Cumulative
                  effect of accounting change, net of taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            .05Reduction
                  in propane litigation accrual upon settlement
            
            
            -
            
            
            .04
            
            
            -
            
            
            .04GAAP-adjusted
                  net earnings per share from operations
            
            $
            .47
            
            $
            .46
            
            $
            1.20
            
            $
            1.26





*Discussion
      of adjustments*





The
      cumulative effect of accounting change resulted from the Company’s adoption of
      Statement of Financial Accounting Standards (SFAS) No. 123 (revised
      2004),*“Share-Based Payment”*(SFAS 123(R)).  The reduction in
      propane litigation accrual resulted from the propane litigation being settled
      for an amount that was less than had been accrued previously.  This
      reduction appears in the income statement as a reduction to other
      expenses.




Management
      believes that these adjustments are appropriate in determining the non-GAAP
      financial performance measure. Management utilizes such measure in exercising
      budgetary control, managing business operations and determining eligibility
      for
      certain incentive compensation payments. The non-GAAP measure, GAAP-adjusted
      net
      earnings per share from operations, provides a consistent basis upon which
      to
      measure performance by excluding the cumulative effect on per share earnings
      of
      the accounting change resulting from the Company’s adoption of SFAS 123(R) and
      of litigation related to the sale of a prior business.





*Second
      Quarter*





GAAP-adjusted
      net earnings per share from operations increased primarily due to a higher
      gas
      margin of $.05 and a higher electric margin of $.02.  These increases
      were partially offset by higher operating expenses of
      $.06.  Accelerated depreciation on the Lake Murray back-up dam and
      recognition of synthetic fuel tax credits and related items had no effect on
      net
      income, as discussed at Income Taxes - *Recognition of Synthetic Fuel Tax
      Credits*.





*Year
      to Date*





GAAP-adjusted
      net earnings per share from operations decreased primarily due to higher
      operating expenses of $.17 and dilution of $.02.  These decreases were
      partially offset by higher natural gas margin of $.12 and higher electric margin
      of $.01.  Accelerated depreciation on the Lake Murray back-up dam and
      recognition of synthetic fuel tax credits and related items had no effect on
      net
      income, as discussed at Income Taxes - *Recognition of Synthetic Fuel Tax
      Credits*.


Table
          of Contents


**Dividends
      Declared**





The
      Company’s Board of Directors has declared the following dividends on common
      stock during 2007:





Declaration
                Date
            Dividend
                Per Share
            Record Date
            Payment DateFebruary
                  15, 2007
            $.44
            March
                  9, 2007
            April
                  1, 2007April
                  26, 2007
            .44
            June
                  11, 2007
            July
                  1, 2007August
                  2, 2007
            .44
            September
                  10, 2007
            October
                  1, 2007





**Electric
      Operations**





Electric
      Operations is comprised of the electric operations of South Carolina Electric
      & Gas Company (SCE&G), South Carolina Generating Company, Inc. (GENCO)
      and South Carolina Fuel Company, Inc. Electric operations sales margin
      (including transactions with affiliates) was as follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                revenues
            
            $
            470.0
            
            2.0
            %
            $
            460.8
            
            $
            912.7
            
            6.2
            %
            $
            859.5Less:  Fuel
                used in generation
            
            
            152.9
            
            4.3
            %
            
            146.6
            
            
            308.8
            
            16.9
            %
            
            264.1Purchased
                power
            
            
            6.6
            
            (19.5)
            %
            
            8.2
            
            
            18.0
            
            51.3
            %
            
            11.9Margin
            
            $
            310.5
            
            1.5
            %
            $
            306.0
            
            $
            585.9
            
            0.4
            %
            $
            583.5


*Greater
      than 100%





*Second
      Quarter*





Margin
      increased by $11.1 million due to customer growth and usage.  This
      increase was partially offset by $5.6 million due to lower off-system
      sales.





*Year
      to Date*





Margin
      increased by $19.1 million due to customer growth and usage.  This
      increase was partially offset by $16.3 million due to lower off-system
      sales.





**Gas
      Distribution**





Gas
      Distribution is comprised of the local distribution operations of SCE&G and
      Public Service Company of North Carolina, Incorporated (PSNC Energy). Gas
      distribution sales margin (including transactions with affiliates) was as
      follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                revenues
            
            $
            189.5
            
            14.6
            %
            $
            165.4
            
            $
            622.5
            
            1.8
            %
            $
            611.2Less:
                Gas purchased for resale
            
            
            133.4
            
            10.2
            %
            
            121.0
            
            
            436.9
            
            (4.3)
            %
            
            456.7Margin
            
            $
            56.1
            
            26.4
            %
            $
            44.4
            
            $
            185.6
            
            20.1
            %
            $
            154.5





*Second
                Quarter*





Margin
      at
      SCE&G increased by $3.3 million due to the Public Service Commission of
      South Carolina (SCPSC)-approved increase to retail gas base rates effective
      with
      the first billing cycle in November 2006 and by $1.9 million due to customer
      growth.  Margin at PSNC Energy increased by $ 3.9 million
      due to the North Carolina Utilities Commission (NCUC)-approved rate increase
      effective for services rendered on or after November 1, 2006 and by $1.6 million
      due to customer growth and usage.





*Year
      to Date*





Margin
      at
      SCE&G increased by $10.8 million due to the SCPSC-approved increase to
      retail gas base rates and by $2.2 million due to customer
      growth.  Margin at PSNC Energy increased by $ 9.1 million
      due to the NCUC-approved rate increase effective for services rendered on or
      after November 1, 2006 and by $6.2 million due to customer growth and
      usage.




Table
          of Contents





**Gas
      Transmission**





Gas
      Transmission is comprised of the operations of Carolina Gas Transmission
      Corporation (CGTC) and, for periods prior to the name change and merger, South
      Carolina Pipeline Corporation and SCG Pipeline, Inc., for all periods presented.
      Gas transmission sales margin (including transactions with affiliates) was
      as
      follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Transportation
                revenue
            
            $
            11.3
            
            *
            
            $
            5.5
            
            $
            23.5
            
            *
            
            $
            10.9Other
                operating revenues
            
            
            0.6
            
            **
            
            
            118.1
            
            
            1.5
            
            **
            
            
            336.3Less:
                Gas purchased for resale
            
            
            -
            
            **
            
            
            107.3
            
            
            -
            
            **
            
            
            313.8Margin
            
            $
            11.9
            
            (27.0)
            %
            $
            16.3
            
            $
            25.0
            
            (25.1)
            %
            $
            33.4


*Greater
      than 100%


**
      Change
      not meaningful due to change in business model.





*Second
                Quarter and Year to Date*





Transportation revenue increased as a result of the change to an open access,
      transportation-only interstate pipeline business model effective November 1,
      2006.  As a result of this change, CGTC no longer earns commodity gas
      revenues, nor does it incur gas cost.





**Retail
      Gas Marketing**





Retail
      Gas Marketing is comprised of SCANA Energy, which operates in Georgia’s natural
      gas market. Retail Gas Marketing operating revenues and net income were as
      follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                revenues
            
            $
            102.2
            
            12.1
            %
            $
            91.2
            
            $
            343.0
            
            (5.3
            )%
            $
            362.1Net
                income
            
            $
            1.4
            
            (39.1
            )%
            $
            2.3
            
            $
            19.7
            
            (16.9
            )%
            $
            23.7





*Second
      Quarter*





Operating
      revenues increased primarily as a result of higher average retail prices which
      were partially offset by lower volume.**Net income decreased
      primarily due to higher expenses, including bad debt expense, and lower
      margin.





*Year
      to Date*





Operating
      revenues decreased primarily as a result of lower average retail prices which
      were partially offset by higher volume. **Net income decreased
      primarily due to higher expenses, including bad debt expense, and lower
      margin.





**Energy
      Marketing**





Energy
      Marketing is comprised of the Company’s non-regulated marketing operations,
      excluding SCANA Energy. Energy Marketing operating revenues and net income
      (loss) were as follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                revenues
            
            $
            288.0
            
            45.6
            %
            $
            197.8
            
            $
            593.1
            
            43.5
            %
            $
            413.4Net
                income (loss)
            
            $
            0.8
            
            *
            
            $
            (0.6)
            
            $
            0.8
            
            *
            
            $
            (0.6)


*Greater
      than 100%





*Second
      Quarter*





Operating
      revenues increased primarily due to customer growth, some of which results
      from
      customers formerly reported in the Gas Transmission segment now being reported
      in Energy Marketing.  Net income increased primarily due to higher
      margins.





*Year
      to Date*





Operating
      revenues increased primarily due to customer growth, some of which results
      from
      customers formerly reported in the Gas Transmission segment now being reported
      in Energy Marketing.  Net income increased primarily due to higher
      margins of $1.7 million, which were partially offset by increased operating
      expenses of $0.6 million.


Table
          of Contents




**Other
      Operating Expenses**





Other
      operating expenses arising from the operating segments previously discussed
      were
      as follows:





Second
                Quarter
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Other
                operation and maintenance
            
            $
            160.1
            
            6.7
            %
            $
            150.1
            
            $
            334.1
            
            9.0
            %
            $
            306.6Depreciation
                and amortization
            
            
            85.8
            
            11.3
            %
            
            77.1
            
            
            176.9
            
            15.4
            %
            
            153.3Other
                taxes
            
            
            38.5
            
            3.5
            %
            
            37.2
            
            
            79.4
            
            4.6
            %
            
            75.9





*Second
      Quarter*





Other
      operation and maintenance expenses increased primarily due to higher incentive
      compensation and other benefit costs.  Depreciation and amortization
      expense increased by $5.9 million due to lower estimated phase-out of synthetic
      fuel tax credits related to the back-up dam at Lake Murray (see Income
      Taxes-*Recognition of Synthetic Fuel Tax Credits*) and by $2.5 million
      due to net property additions.  Other taxes increased due to higher
      property taxes.





*Year
      to Date*





Other
      operation and maintenance expenses increased by $8.5 million due to higher
      electric generation, transmission and distribution expenses, by $9.6 million
      due
      to higher incentive compensation and other benefit costs and by $4.0 million
      due
      to higher bad debt expense.  Depreciation and amortization expense
      increased by $17.8 million due to lower estimated phase-out of synthetic fuel
      tax credits related to the back-up dam at Lake Murray (see Income
      Taxes-*Recognition of Synthetic Fuel Tax Credits*) and by $4.9 million
      due to net property additions.  Other taxes increased due to higher
      property taxes.





**Other
      Income (Expense*)***





Other
      income (expense) includes the results of certain incidental (non-utility)
      activities and the activities of certain non-regulated subsidiaries. Other
      income (expense) declined in 2007 compared to 2006 primarily due to lower
      carrying cost recovery recognition on the unrecovered balance of the
      Lake Murray back-up dam project.





**Income
      Taxes**





Income
      tax expense decreased primarily due to changes in operating income and due
      to
      the recognition at SCE&G of $18.5 million in synthetic fuel tax credits
      during the first half of 2007 compared to $8.8 million during the same period
      in
      2006.





*Recognition
      of Synthetic Fuel Tax Credits*





SCE&G
      holds equity-method investments in two partnerships involved in converting
      coal
      to synthetic fuel, the use of which fuel qualifies for federal income tax
      credits. Under an accounting methodology approved by SCPSC in a January 2005
      order, construction costs related to the Lake Murray back-up dam project are
      recorded in utility plant in service in a special dam remediation account,
      outside of rate base, and depreciation is being recognized against the balance
      in this account on an accelerated basis, subject to the availability of the
      synthetic fuel tax credits.


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          of Contents





The
      level
      of depreciation expense and related tax benefit recognized in the income
      statement is equal to the available synthetic fuel tax credits, less partnership
      losses and other expenses, net of taxes. As a result, the balance of unrecovered
      costs in the dam remediation account declines as accelerated depreciation is
      recorded. Although these entries collectively have no impact on consolidated
      net
      income, they can have a significant impact on individual line items within
      the
      income statement. The accelerated depreciation, synthetic fuel tax credits,
      partnership losses and the income tax benefit arising from such losses
      recognized by SCE&G during the three and six months ended June 30, 2007 and
      2006 are as follows:





Second
                Quarter
            
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            
            2006
            
            2007
            
            2006Depreciation
                  and amortization expense
            
            $
            (7.1
            )
            $
            (1.2
            )
            $
            (19.1)
            
            $
            (1.4
            )Income
                  tax benefits:From
                  synthetic fuel tax credits
            
            
            6.8
            
            
            3.3
            
            
            17.7
            
            
            6.6From
                  accelerated depreciation
            
            
            2.7
            
            
            0.5
            
            
            7.3
            
            
            0.6From
                  partnership losses
            
            
            1.5
            
            
            1.5
            
            
            3.6
            
            
            3.5Total
                  income tax benefits
            
            
            11.0
            
            
            5.3
            
            
            28.6
            
            
            10.7Losses
                  from Equity Method Investments
            
            
            (3.9
            )
            
            (4.1
            )
            
            (9.5)
            
            
            (9.3
            )Impact
                  on Net Income
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -





Depreciation
      on the Lake Murray back-up dam remediation account will be matched to
      available synthetic fuel tax credits on a quarterly basis until all of the
      available synthetic fuel tax credits have been utilized. The synthetic fuel
      tax
      credit program expires at the end of 2007.




The
      availability of the synthetic fuel tax credits is dependent on several factors,
      one of which is the average annual domestic wellhead price per barrel of crude
      oil as published by the U.S. Government. Under a phase-out provision included
      in
      the program, if the domestic wellhead reference price of oil per barrel for
      a
      given year is below an inflation-adjusted benchmark range for that year, all
      of
      the synthetic fuel tax credits that have been generated in that year would
      be
      available for use. If that price is above the benchmark range, none of the
      tax
      credits would be available. If that price falls within the benchmark range,
      a
      calculated portion of the credits would be available.





The
      benchmark price range for 2006, published in April 2007, is $55 to $69 per
      barrel, resulting in a phase-out of 33 percent for 2006. SCE&G’s analysis
      indicates that the available synthetic fuel tax credits for 2007 also are
      likely to be impacted by the phase-out calculation. As such, through June 2007
      the Company recorded synthetic fuel tax credits and applied those credits to
      allow the recording of accelerated depreciation related to the balance in the
      dam remediation project account based on an estimate that only 74.5 percent
      of
      credits generated in 2007 will be available (phase-out of 25.5 percent). The
      Company cannot predict what impact, if any, the price of oil may have on the
      Company’s ability to earn and utilize synthetic fuel tax credits in the future.
      However, there is significant uncertainty as to the continued availability
      of
      the credits in 2007. The availability of these synthetic fuel tax credits is
      also subject to coal availability and other operational risks related to the
      generating plants.





The
      Company does not expect available credits to be sufficient to fully recover
      the
      construction costs of dam remediation, and the total unrecovered cost at the
      end
      of 2007 may be significant. To the extent that available credits are not
      sufficient to fully recover the construction costs of the dam remediation,
      regulatory action to allow recovery of those remaining costs will likely be
      sought. As of June 30, 2007, remaining unrecovered costs, based on management’s
      recording of accelerated depreciation and related tax benefits, were $54.0
      million.





Finally,
      SCANA, through a subsidiary, provides management and maintenance services for
      a
      non-affiliated synthetic fuel production facility. Reduced synthetic fuel tax
      credit availability under the above phase-out provisions also adversely impacts
      the level of payment SCANA receives for these services.





**LIQUIDITY
      AND CAPITAL RESOURCES**





The
      Company anticipates that its contractual cash obligations will be met through
      internally generated funds, the incurrence of additional short- and
      long-term indebtedness and sales of equity securities. The Company expects
      that
      it has or can obtain adequate sources of financing to meet its projected cash
      requirements for the foreseeable future. The Company’s ratios of earnings to
      fixed charges for the six and 12 months ended June 30, 2007
      were 2.68 and 2.78, respectively.


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





SCE&G
      expects to add additional base load electric generation in the 2015 to 2016
      timeframe.  Based on an evaluation of alternatives, SCE&G and
      Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer
      Station) have selected the Summer Station site as the preferred site for new
      nuclear generation. Due to the significant lead time required for construction
      of nuclear generation, the joint owners are preparing an application to the
      Nuclear Regulatory Commission (NRC) for a combined construction and operating
      license (COL) that would cover two new nuclear units. The COL application,
      which
      is expected to be completed and filed in 2007, would be reviewed by the NRC
      for
      an estimated three years. While SCE&G’s current plans are to pursue the
      development of one or both of these nuclear units, these plans will continue
      to
      be influenced by many factors, including NRC licensing attainment, ongoing
      evaluation of relative construction and operating costs, the cost of competing
      fuels, regulatory and environmental requirements and financial market
      conditions.





In
      May 2007, the Base Load Review Act
      (the Act) became law in South Carolina.  This law is intended to allow
      a utility to recover prudently incurred capital and operating costs associated
      with new nuclear or coal-fired base load electric generating facilities larger
      than 350 megawatts.  Based on an application filed by the utility
      under the Act, the SCPSC would review and rule on the prudency of the decision
      to build the plant.  If the decision was found to be prudent, that
      finding would be binding on all future proceedings so long as the plant is
      constructed in accordance with the schedules, estimates and projections set
      forth in the approved application.  In addition, beginning with the
      initial proceeding, the utility would be allowed to file revised rates with
      the
      SCPSC each year to incorporate any nuclear construction work in progress
      incurred.  Requested rate adjustments would be based on the utility’s
      updated cost of debt and capital structure.  The cost of service and
      rate design would be based on the rates approved in the utility’s most recent
      electric rate order.  The utility may choose to file for a
      project-specific return on common equity or use the return from its most recent
      rate proceeding if the proceeding is less than five years old.





The
      Company’s issuance of various securities, including short- and long-term debt,
      is subject to customary approval or authorization by state and federal
      regulatory bodies, including state public service commissions and the Federal
      Energy Regulatory Commission (FERC).





On
      February 15, 2007, SCANA redeemed at
      maturity $25 million of its medium-term notes which bore interest at
      6.9%.





In
      June
      2007 SCANA entered into an agreement to issue and sell Floating Rate Senior
      Notes due June 1, 2034, in an aggregate principal amount of between $90 million
      and $110 million.  The notes are to be issued at intervals between
      December 2007 and June 2009.  The proceeds of the notes will be used
      for general corporate purposes including financing the construction and
      development of headquarters facilities.  At June 30, 2007 SCANA had
      not issued any notes pursuant to the agreement.





Pursuant
      to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC
      authority to issue short-term debt. Effective February 8, 2006 the FERC has
      authorized SCE&G and GENCO to issue up to $700 million and $100 million,
      respectively, of unsecured promissory notes or commercial paper with maturity
      dates of one year or less. This authorization expires February 7,
      2008.





**ENVIRONMENTAL
      AND REGULATORY MATTERS**





The
      EPA
      has undertaken an aggressive enforcement initiative and the United States
      Department of Justice (DOJ) has brought suit against a number of utilities
      in
      federal court alleging violations of the Clean Air Act (CAA). At least two
      of
      these suits have either been tried or have had substantive motions
      decided—neither favorable to the industry. One of the decisions is not believed
      to be binding as precedent and the other one, described more fully
      below, may be.




On
      April
      2, 2007, in a unanimous ruling, the U.S. Supreme Court vacated a decision by
      the
      U.S. Court of Appeals for the Fourth Circuit that effectively halted the EPA
      enforcement action against Duke Energy Corporation (Duke) for allegedly
      performing plant modifications without a required permit.  Such
      modifications for life extension and modernization as performed by Duke and
      other utilities, including SCE&G, were common within the industry. 
Hence this decision may heighten the potential exposure of utilities to
      enforcement actions such as those already brought against Duke and others,
      many
      of which had not proceeded pending this Supreme Court decision.




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          of Contents


Although
      the
      Supreme Court overturned the lower courts’ decisions, some issues were not ruled
      upon and were remanded to the lower courts where they may receive further
      consideration.  Several arguments are expected to continue during the
      remand proceedings. For example, Duke argued that the EPA has taken inconsistent
      positions in its interpretations of “routine maintenance, repair and
      replacement” and is now “retroactively targeting twenty years of accepted
      practice.” The Supreme Court noted that this issue was not addressed by the
      lower court decisions, and, to the extent it is not procedurally foreclosed,
      Duke may raise it on remand.




Prior
      to
      the suits, those utilities had received requests for information under
      Section 114 of the CAA and were issued Notices of Violation. The basis for
      these suits is the assertion by the EPA, under a stringent rule known as New
      Source Review (NSR), that certain maintenance activities undertaken by the
      utilities constitute “major modifications” which would have required the
      installation of costly Best Available Control Technology (BACT). SCE&G and
      GENCO have previously received and responded to Section 114 requests for
      information related to Canadys, Wateree and Williams Stations. The regulations
      under the CAA provide certain exemptions to the definition of “major
      modifications,” including an exemption for routine repair, replacement or
      maintenance. On October 27, 2003, the EPA published a final revised NSR
      rule in the Federal Register with an effective date of December 26, 2003.
      The rule represents an industry-favorable departure from certain positions
      advanced by the federal government in the NSR enforcement initiative. However,
      on motion of several Northeastern states, the United States Circuit Court of
      Appeals for the District of Columbia stayed the effect of the final rule. Even
      with the recent Supreme Court action described above, the ultimate application
      of the final rule to the Company is uncertain. The Company has analyzed each
      of
      the activities covered by the EPA’s requests and believes each of these
      activities is covered by the exemption for routine repair, replacement and
      maintenance under what it believes is a fair reading of both the prior
      regulation and the contested revised regulation. The regulations also provide
      an
      exemption for an increase in emissions resulting from increased hours of
      operation or production rate and from demand growth.





The
      current state of continued DOJ enforcement actions continues to be the subject
      of industry-wide speculation, but it is possible that the EPA will commence
      enforcement actions against SCE&G and GENCO, and the EPA has the authority
      to seek penalties at the rate of up to $27,500 per day for each violation.
      The
      EPA also could seek installation of BACT (or equivalent) at the three plants.
      The Company continues to believe that any enforcement actions relative to the
      Company’s compliance with the CAA would be without merit. The Company has
      completed installation of selective catalytic reactors at Wateree and Williams
      for nitrogen oxides control and is proceeding with plans to install sulfur
      dioxide scrubbers at both of these stations to meet Clean Air Interstate Rule
      (CAIR) regulations. These actions would mitigate many of the concerns with
      NSR.
      SCE&G and GENCO expect to incur capital expenditures totaling approximately
      $450 million over the 2007-2010 period to install this new equipment.
      SCE&G and GENCO also expect to have increased operation and maintenance
      costs related to this equipment of approximately $3.4 million in 2009 and
      $23 million in 2010 and each subsequent year thereafter. To meet compliance
      requirements for the years 2012 through 2016, the Company anticipates additional
      capital expenditures totaling approximately $480 million.





See
      notes
      to the condensed consolidated financial statements for additional information
      related to environmental matters (Note 5B) and regulatory matters (Note
      2).





**OTHERS
      MATTERS**





In
      June 2007 the Georgia Public Service
      Commission (GPSC) announced that SCANA Energy will continue to serve as
      Georgia’s regulated provider of natural gas until August 31, 2009 with an option
      for a third year if approved by the GPSC.  SCANA Energy has been
      Georgia’s regulated provider since the program began in 2002.  At June
      30, 2007 SCANA Energy’s regulated division served approximately 98,000
      customers.


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          of Contents





**ITEM
      3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK**





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





Interest
      rate risk - The table below provides information about long-term debt issued
      by
      the Company and other financial instruments that are sensitive to changes in
      interest rates. For debt obligations, the table presents principal cash flows
      and related weighted average interest rates by expected maturity dates. For
      interest rate swaps, the figures shown reflect notional amounts and related
      maturities. Fair values for debt and swaps represent quoted market
      prices.





As
                of June 30, 2007
            
            Expected
                MaturityThere-
            
            FairMillions
                of dollars
            
            2007
            2008
            2009
            2010
            2011
            After
            Total
            ValueLong-Term
                  Debt Issued:Fixed
                  Rate ($)
            
            5.0
            123.2
            108.2
            14.8
            619.3
            2,023.6
            2,894.1
            2,991.7Average
                  Fixed Interest Rate (%)
            
            7.51
            5.96
            6.27
            6.87
            6.78
            5.95
            6.15
            n/aVariable
                  Rate ($)
            
            
            100.0
            
            
            
            
            100.0
            100.2Average
                  Variable Interest Rate (%)
            
            
            5.51
            
            
            
            
            5.51
            n/aInterest
                  Rate Swap:Pay
                  Variable/Receive Fixed ($)
            
            -
            3.2
            3.2
            3.2
            3.2
            3.2
            16.0
            -Average Pay Interest Rate (%)
            
            -
            8.55
            8.55
            8.55
            8.55
            8.55
            8.55
            n/aAverage Receive Interest Rate (%)
            
            -
            8.75
            8.75
            8.75
            8.75
            8.75
            8.75
            n/a




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





In
      June
      2007 SCANA entered into an agreement to issue and sell Floating Rate Senior
      Notes due June 1, 2034, in an aggregate principal amount of between $90 million
      and $110 million.  The notes are to be issued at intervals between
      December 2007 and June 2009.  At June 30, 2007 the estimated fair
      value of the Company’s forward starting interest rate swap related to the
      Floating Rate Senior Notes totaled $0.3 million (gain).  These notes
      and the swap are not depicted in the table above.





Commodity
      price risk - The following tables provide information about the Company’s
      financial instruments that are sensitive to changes in natural gas prices.
      Weighted average settlement prices are per 10,000 dekatherms. Fair value
      represents quoted market prices.





Expected
                Maturity:Futures
                Contracts
            
            
            OptionsPurchased
                Call
            Sold
                Call
            Sold
                Put2007
            Long
            Short
            
            
            
            (Short)
            (Long)Settlement
                  Price (a)
            7.55
            7.91
            
            Strike
                  Price (a)
            8.75
            12.23
            6.13Contract
                  Amount (b)
            13.9
            1.1
            
            Contract
                  Amount (b)
            5.1
            1.3
            0.5Fair
                  Value (b)
            12.8
            1.0
            
            Fair
                  Value (b)
            0.4
            -
            -2008Settlement
                  Price (a)
            8.63
            -
            
            Strike
                  Price (a)
            9.33
            14.00
            -Contract
                  Amount (b)
            30.1
            -
            
            Contract
                  Amount (b)
            6.1
            1.4
            -Fair
                  Value (b)
            29.5
            -
            
            Fair
                  Value (b)
            0.7
            -
            -(a)  
                  Weighted average, in dollars(b) 
                  Millions of dollars




Table
          of Contents





Expected
                MaturitySwaps
            2007
            2008
            2009Commodity
                  Swaps:Pay
                  fixed/receive variable (b)
            105.4
            150.6
            13.7Average
                  pay rate (a)
            8.8068
            9.2045
            9.8157Average
                  received rate (a)
            7.6304
            8.6376
            9.4054Fair
                  value (b)
            91.3
            141.3
            13.1Pay
                  variable/receive fixed (b)
            1.8
            3.2
            52.0Average
                  pay rate (a)
            7.3546
            8.6194
            7.9980Average
                  received rate (a)
            8.2571
            8.8361
            7.2500Fair
                  value (b)
            2.0
            3.3
            -Basis
                  Swaps:Pay
                  variable/receive variable (b)
            13.0
            10.7
            4.2Average
                  pay rate (a)
            7.4637
            8.6075
            8.6548Average
                  received rate (a)
            7.4555
            8.5897
            8.6124Fair
                  value (b)
            13.0
            10.7
            4.1(a)  
                  Weighted average, in dollars(b) 
                  Millions of dollars








**ITEM
      4. CONTROLS AND
      PROCEDURES**





As
      of
      June 30, 2007, SCANA Corporation (SCANA) conducted an evaluation under the
      supervision and with the participation of its management, including its Chief
      Executive Officer (CEO) and Chief Financial Officer (CFO), of (a) the
      effectiveness of the design and operation of its disclosure controls and
      procedures and (b) any change in its internal control over financial reporting.
      Based on this evaluation, the CEO and CFO concluded that, as of June 30,
      2007, SCANA’s disclosure controls and procedures were effective. There has
      been no change in SCANA’s internal control over financial reporting during
      the quarter ended June 30, 2007 that has materially affected or is reasonably
      likely to materially affect SCANA’s internal control over financial
      reporting.






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**SOUTH
      CAROLINA ELECTRIC & GAS COMPANY**


**FINANCIAL
      SECTION**







































































Table
          of Contents




**ITEM
      1. FINANCIAL STATEMENTS**





SOUTH
      CAROLINA ELECTRIC & GAS COMPANY


CONDENSED
      CONSOLIDATED BALANCE SHEETS


(Unaudited)





June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006AssetsUtility
                  Plant In Service
            
            $
            8,106
            
            
            $
            7,876Accumulated
                  Depreciation and Amortization
            
            
            (2,578
            )
            
            
            (2,483
            )5,528
            
            
            
            5,393Construction
                  Work in Progress
            
            
            294
            
            
            
            316Nuclear
                  Fuel, Net of Accumulated Amortization
            
            
            66
            
            
            
            39Utility
                  Plant, Net
            
            
            5,888
            
            
            
            5,748Nonutility
                  Property and Investments:Nonutility property, net of accumulated depreciation
            
            
            32
            
            
            
            31Assets held in trust, net - nuclear decommissioning
            
            
            58
            
            
            
            56Other investments
            
            
            25
            
            
            
            25Nonutility Property and Investments, Net
            
            
            115
            
            
            
            112Current
                  Assets:Cash and cash equivalents
            
            
            15
            
            
            
            24Receivables, net of allowance for uncollectible accounts of $6
                  and $5
            
            
            307
            
            
            
            311Receivables - affiliated companies
            
            
            28
            
            
            
            41Inventories (at average cost):Fuel
            
            
            147
            
            
            
            147Materials and supplies
            
            
            90
            
            
            
            85Emission allowances
            
            
            43
            
            
            
            22Prepayments
                  and other
            
            
            25
            
            
            
            20Deferred
                  income taxes
            
            
            18
            
            
            
            19Total Current Assets
            
            
            673
            
            
            
            669Deferred
                  Debits and Other Assets:Pension asset, net
            
            
            212
            
            
            
            200Due from affiliates - pension and postretirement
                  benefits
            
            
            44
            
            
            
            41Emission allowances
            
            
            -
            
            
            
            27Regulatory assets
            
            
            678
            
            
            
            702Other
            
            
            100
            
            
            
            127Total Deferred Debits and Other Assets
            
            
            1,034
            
            
            
            1,097Total
            
            $
            7,710
            
            
            $
            7,626






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          of Contents




June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006Capitalization
                  and LiabilitiesShareholders’
                  Investment:Common equity
            
            $
            2,537
            
            
            $
            2,457Preferred stock (Not subject to purchase or sinking
                  funds)
            
            
            106
            
            
            
            106Total Shareholders’ Investment
            
            
            2,643
            
            
            
            2,563Preferred
                  Stock, net (Subject to purchase or sinking funds)
            
            
            7
            
            
            
            8Long-Term
                  Debt, net
            
            
            2,005
            
            
            
            2,008Total
                  Capitalization
            
            
            4,655
            
            
            
            4,579Minority
                  Interest
            
            
            87
            
            
            
            86Current
                  Liabilities:Short-term borrowings
            
            
            415
            
            
            
            362Current portion of long-term debt
            
            
            13
            
            
            
            14Accounts payable
            
            
            103
            
            
            
            155Accounts payable - affiliated companies
            
            
            164
            
            
            
            147Customer deposits and customer prepayments
            
            
            41
            
            
            
            40Taxes accrued
            
            
            83
            
            
            
            112Interest accrued
            
            
            34
            
            
            
            33Dividends declared
            
            
            42
            
            
            
            23Other
            
            
            41
            
            
            
            63Total Current Liabilities
            
            
            936
            
            
            
            949Deferred
                  Credits and Other Liabilities:Deferred income taxes, net
            
            
            800
            
            
            
            807Deferred investment tax credits
            
            
            103
            
            
            
            118Asset retirement obligations
            
            
            287
            
            
            
            279Postretirement benefits
            
            
            197
            
            
            
            194Due to affiliates - pension and postretirement
                  benefits
            
            
            6
            
            
            
            6Regulatory liabilities
            
            
            571
            
            
            
            541Other
            
            
            68
            
            
            
            67Total Deferred Credits and Other Liabilities
            
            
            2,032
            
            
            
            2,012Commitments
                  and Contingencies (Note 4)
            
            
            -
            
            
            
            -Total
            
            $
            7,710
            
            
            $
            7,626





See
      Notes
      to Condensed Consolidated Financial Statements.




Table
          of Contents


SOUTH
      CAROLINA ELECTRIC & GAS COMPANY


CONDENSED
      CONSOLIDATED STATEMENTS OF
      INCOME


(Unaudited)








Three
                Months Ended
            
            
            Six
                Months EndedJune
                30,
            
            
            June
                30,Millions
                of dollars
            
            2007
            
            
            2006
            
            
            2007
            
            
            2006Operating
                  Revenues:Electric
            
            $
            472
            
            
            $
            464
            
            
            $
            917
            
            
            $
            864Gas
            
            
            103
            
            
            
            89
            
            
            
            292
            
            
            
            281Total Operating Revenues
            
            
            575
            
            
            
            553
            
            
            
            1,209
            
            
            
            1,145Operating
                  Expenses:Fuel used in electric generation
            
            
            153
            
            
            
            147
            
            
            
            309
            
            
            
            264Purchased power
            
            
            7
            
            
            
            8
            
            
            
            18
            
            
            
            12Gas purchased for resale
            
            
            81
            
            
            
            72
            
            
            
            220
            
            
            
            225Other operation and maintenance
            
            
            116
            
            
            
            114
            
            
            
            246
            
            
            
            229Depreciation and amortization
            
            
            74
            
            
            
            65
            
            
            
            153
            
            
            
            130Other taxes
            
            
            35
            
            
            
            34
            
            
            
            73
            
            
            
            69Total Operating Expenses
            
            
            466
            
            
            
            440
            
            
            
            1,019
            
            
            
            929Operating
                  Income
            
            
            109
            
            
            
            113
            
            
            
            190
            
            
            
            216Other
                  Income (Expense):Other income
            
            
            7
            
            
            
            5
            
            
            
            13
            
            
            
            44Other expenses
            
            
            (2
            )
            
            
            (1
            )
            
            
            (6
            )
            
            
            (36
            )Interest charges, net of allowance for borrowed
                  fundsused during construction of $3, $2, $5 and $3
            
            
            (35
            )
            
            
            (36
            )
            
            
            (71
            )
            
            
            (72
            )Gain
                  on sale of assets
            
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            -Allowance
                  for equity funds used during construction
            
            
            1
            
            
            
            -
            
            
            
            1
            
            
            
            -Total
                  Other Expense
            
            
            (29
            )
            
            
            (32
            )
            
            
            (62
            )
            
            
            (64
            )Income
                  Before Income Taxes, Losses from EquityMethod Investments, Minority Interest, Cumulative Effect
                  ofAccounting Change and Preferred Stock Dividends
            
            
            80
            
            
            
            81
            
            
            
            128
            
            
            
            152Income
                  Tax Expense
            
            
            20
            
            
            
            23
            
            
            
            23
            
            
            
            41Income
                  Before Losses from Equity Method Investments,Minority Interest, Cumulative Effect of Accounting
                  Changeand Preferred Stock Dividends
            
            
            60
            
            
            
            58
            
            
            
            105
            
            
            
            111Losses
                  from Equity Method Investments
            
            
            (4
            )
            
            
            (4
            )
            
            
            (10
            )
            
            
            (10
            )Minority
                  Interest
            
            
            2
            
            
            
            1
            
            
            
            4
            
            
            
            3Cumulative
                  Effect of Accounting Change, net of taxes
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            4Net
                  Income
            
            
            54
            
            
            
            53
            
            
            
            91
            
            
            
            102Preferred
                  Stock Cash Dividends Declared
            
            
            2
            
            
            
            2
            
            
            
            4
            
            
            
            4Earnings
                  Available for Common Shareholder
            
            $
            52
            
            
            $
            51
            
            
            $
            87
            
            
            $
            98See
                  Notes to Condensed Consolidated Financial
                  Statements.




Table
          of Contents


SOUTH
      CAROLINA ELECTRIC & GAS COMPANY


CONDENSED
      CONSOLIDATED STATEMENTS OF CASH
      FLOWS


(Unaudited)





Six
                Months EndedJune
                30,Millions
                of dollars
            
            2007
            
            
            2006Cash
                  Flows From Operating Activities:Net income
            
            $
            91
            
            
            $
            102Adjustments to Reconcile Net Income to Net Cash Provided From Operating
                  Activities:Cumulative effect of accounting change, net of taxes
            
            
            -
            
            
            
            (4
            )Losses from equity method investments
            
            
            10
            
            
            
            10Minority interest
            
            
            4
            
            
            
            3Depreciation and amortization
            
            
            152
            
            
            
            130Amortization of nuclear fuel
            
            
            9
            
            
            
            9Carrying cost recovery
            
            
            (1
            )
            
            
            (4
            )Gain
                  of sale of assets
            
            
            (1
            )
            
            
            -Cash provided (used) by changes in certain assets and
                  liabilities:Receivables, net
            
            
            (5
            )
            
            
            41Inventories
            
            
            (27
            )
            
            
            (28
            )Prepayments
            
            
            (5
            )
            
            
            (11
            )Pension asset
            
            
            (11
            )
            
            
            (7
            )Other regulatory assets
            
            
            6
            
            
            
            11Deferred income taxes, net
            
            
            (6
            )
            
            
            13Regulatory liabilities
            
            
            16
            
            
            
            18Postretirement benefits
            
            
            3
            
            
            
            4Accounts payable
            
            
            (17
            )
            
            
            (41
            )Taxes accrued
            
            
            (29
            )
            
            
            (47
            )Interest accrued
            
            
            1
            
            
            
            (1
            )Changes
                  in fuel adjustment clauses
            
            
            1
            
            
            
            29Changes in other assets
            
            
            20
            
            
            
            11Changes in other liabilities
            
            
            (25
            )
            
            
            (1
            )Net
                  Cash Provided From Operating Activities
            
            
            186
            
            
            
            237Cash
                  Flows From Investing Activities:Utility
                  property additions and construction expenditures
            
            
            (261
            )
            
            
            (181
            )Non-utility
                  property additions
            
            
            (1
            )
            
            
            -Proceeds
                  from sale of assets
            
            
            1
            
            
            
            -Short-term
              investments-affiliate
            
            
            10
            
            
            
            -Investments
            
            
            (9
            )
            
            
            (17
            )Net
                  Cash Used For Investing Activities
            
            
            (260
            )
            
            
            (198
            )Cash
                  Flows From Financing Activities:Proceeds
                  from issuance of debt
            
            
            -
            
            
            
            123Repayment of debt
            
            
            (4
            )
            
            
            (8
            )Retirement
                  of preferred stock
            
            
            (1
            )
            
            
            -Dividends
            
            
            (61
            )
            
            
            (79
            )Contribution from parent
            
            
            66
            
            
            
            3Short-term borrowings - affiliate, net
            
            
            12
            
            
            
            4Short-term borrowings, net
            
            
            53
            
            
            
            (88
            )Net Cash Provided From (Used For) Financing
                  Activities
            
            
            65
            
            
            
            (45
            )Net
                  Decrease In Cash and Cash Equivalents
            
            
            (9
            )
            
            
            (6
            )Cash
                  and Cash Equivalents, January 1
            
            
            24
            
            
            
            19Cash
                  and Cash Equivalents, June 30
            
            $
            15
            
            
            $
            13Supplemental
                  Cash Flow Information:Cash paid for - Interest (net of capitalized interest of $5 and
                  $3)
            
            $
            67
            
            
            $
            2-
                  Income taxes
            
            
            6
            
            
            
            31Noncash
                  Investing and Financing Activities:Accrued construction expenditures
            
            
            26
            
            
            
            14See
                  Notes to Condensed Consolidated Financial
                  Statements.




Table
          of Contents





SOUTH
      CAROLINA ELECTRIC & GAS COMPANY


NOTES
      TO CONDENSED CONSOLIDATED FINANCIAL
      STATEMENTS


June
      30,
      2007


(Unaudited)





The
      following notes should be read in conjunction with the Notes to Consolidated
      Financial Statements appearing in South Carolina Electric & Gas Company’s
      (SCE&G, and together with its consolidated affiliates, the Company) Annual
      Report on Form 10-K for the year ended December 31, 2006. These are interim
      financial statements, and due to the seasonality of the Company’s business and
      matters that may occur during the rest of the year, the amounts reported in
      the
      Condensed Consolidated Statements of Income are not necessarily indicative
      of
      amounts expected for the full year. In the opinion of management, the
      information furnished herein reflects all adjustments, all of a normal recurring
      nature, which are necessary for a fair statement of the results for the interim
      periods reported.





1.       SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES





A.      Variable
      Interest Entity





Financial
      Accounting Standards Board Interpretation (FIN) 46 (Revised 2003),
*“Consolidation of Variable Interest Entities,”* requires an enterprise’s
      consolidated financial statements to include entities in which the enterprise
      has a controlling financial interest. SCE&G has determined that it has a
      controlling financial interest in South Carolina Generating Company, Inc.
      (GENCO) and South Carolina Fuel Company, Inc. (Fuel Company), and accordingly,
      the accompanying condensed consolidated financial statements include the
      accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and
      Fuel Company are held solely by SCANA Corporation (SCANA), the Company’s parent.
      Accordingly, GENCO’s and Fuel Company’s equity and results of operations are
      reflected as minority interest in the Company’s condensed consolidated financial
      statements.





GENCO
      owns a coal-fired electric generating station with a 615 megawatt net generating
      capacity (summer rating). GENCO’s electricity is sold solely to SCE&G under
      the terms of power purchase and related operating agreements. Fuel Company
      acquires, owns and provides financing for SCE&G’s nuclear fuel, fossil fuel
      and emission allowances. The effects of these transactions are eliminated in
      consolidation. Substantially all of GENCO’s property (carrying value of $274
      million) serves as collateral for its long-term borrowings.





B.      Basis
      of Accounting





The
      Company accounts for its regulated utility operations, assets and liabilities
      in
      accordance with the provisions of Statement of Financial Accounting Standards
      (SFAS) 71, *“Accounting for the Effects of Certain Types of Regulation.”*SFAS 71 requires cost-based rate-regulated utilities to recognize
      in their
      financial statements certain revenues and expenses in different time periods
      than do enterprises that are not rate-regulated. As a result, the Company has
      recorded the regulatory assets and regulatory liabilities summarized as
      follows.





June
                30,
            
            
            December
                31,Millions
                of dollars
            
            2007
            
            
            2006Regulatory
                  Assets:Accumulated
                  deferred income taxes
            
            $
            169
            
            
            $
            169Under-collections-electric
                  fuel and gas cost adjustment clauses
            
            
            31
            
            
            
            49Deferred
                  purchased power costs
            
            
            4
            
            
            
            9Environmental
                  remediation costs
            
            
            17
            
            
            
            18Asset
                  retirement obligations and related funding
            
            
            261
            
            
            
            254Franchise
                  agreements
            
            
            52
            
            
            
            55Deferred
                  regional transmission organization costs
            
            
            7
            
            
            
            8Deferred
                  employee benefit plan costs
            
            
            124
            
            
            
            128Other
            
            
            13
            
            
            
            12Total
                  Regulatory Assets
            
            $
            678
            
            
            $
            702





Regulatory
                  Liabilities:Accumulated
                  deferred income taxes
            
            $
            32
            
            
            $
            34Over-collection
                  - gas cost adjustment clause
            
            
            8
            
            
            
            -Other
                  asset removal costs
            
            
            455
            
            
            
            438Storm
                  damage reserve
            
            
            47
            
            
            
            44Planned
                  major maintenance
            
            
            9
            
            
            
            6Other
            
            
            20
            
            
            
            19Total
                  Regulatory Liabilities
            
            $
            571
            
            
            $
            541




Table
          of Contents





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





Under-
      and over-collections-electric fuel and gas cost adjustment clauses, net,
      represent amounts under- or over-collected from customers pursuant to the fuel
      adjustment clause (electric customers) or gas cost adjustment clause (gas
      customers) as approved by the Public Service Commission of South Carolina
      (SCPSC) during annual hearings. Included in these amounts are regulatory assets
      or liabilities arising from realized and unrealized gains and losses incurred
      in
      the natural gas hedging program of the Company’s regulated
      operations.





Deferred
      purchased power costs represent costs that were necessitated by outages at
      two
      of SCE&G’s base load generating plants in winter 2000-2001. The SCPSC
      approved recovery of these costs in base rates over a three-year period
      beginning January 2005.





Environmental
      remediation costs represent costs associated with the assessment and clean-up
      of
      manufactured gas plant (MGP) sites currently or formerly owned by SCE&G.
      Costs incurred by SCE&G at such sites are being recovered through
      rates.  SCE&G is authorized to amortize $1.4 million of these
      costs on an annual basis.





Asset
      retirement obligations (ARO) and related funding represents the regulatory
      asset
      associated with the legal obligation to decommission and dismantle V. C. Summer
      Nuclear Station (Summer Station) and conditional AROs recorded as required
      by
      SFAS 143,*“Accounting for Asset Retirement Obligations,”*and FIN 47,
*“Accounting for Conditional Asset Retirement Obligations.”*





Franchise
      agreements represent costs associated with electric and gas franchise agreements
      with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC
      order, SCE&G began amortizing these amounts through cost of service rates in
      February 2003 over approximately 20 years.





Deferred
      regional transmission organization costs represent costs incurred by SCE&G
      in the United States Federal Energy Regulatory Commission (FERC)-mandated
      formation of GridSouth. The project was suspended in 2002. Effective January
      2005, the SCPSC approved the amortization of these amounts through cost of
      service rates over five years.





Deferred
      employee benefit plan costs
      represent pension and other postretirement benefit costs which were accrued
      as
      liabilities under provision of SFAS 158, *“Employe**r**s’
Accounting for Defined Benefit Pension and Other Postretirement
      Plans,”***but which are expected to be recovered through
      utility rates.





Other
      asset removal costs represent net collections through depreciation rates of
      estimated costs to be incurred for the future removal of assets.




The
      storm
      damage reserve represents an SCPSC-approved collection through electric rates
      capped at $50 million, which can be applied to offset incremental storm damage
      costs in excess of $2.5 million in a calendar year.  For the six months
      ended June 30, 2007, no amounts were drawn from this reserve.





Planned
      major maintenance related to certain fossil hydro turbine/generation
      equipment and nuclear refueling outages is accrued in advance of the time the
      costs are incurred, as approved through specific SCPSC orders. SCE&G is
      allowed to collect $8.5 million annually over an eight-year period, beginning
      in
      January 2005, through electric rates to offset turbine maintenance expenditures.
       Nuclear refueling charges are accrued during each 18-month refueling
      outage cycle as a component of cost of service.





The
      SCPSC
      has reviewed and approved through specific orders most of the items shown as
      regulatory assets.  Other regulatory assets represent costs which have not
      been approved for recovery by the SCPSC. In recording these costs as regulatory
      assets, management believes the costs will be allowable under existing
      rate-making concepts that are embodied in rate orders received by SCE&G.
      However, ultimate recovery is subject to SCPSC approval. In the future, as
      a
      result of deregulation or other changes in the regulatory environment, the
      Company may no longer meet the criteria for continued application of SFAS 71
      and
      could be required to write off its regulatory assets and liabilities. Such
      an
      event could have a material adverse effect on the Company’s results of
      operations, liquidity or financial position in the period the write-off would
      be
      recorded.





C.      Affiliated
      Transactions





CGTC
      transports natural gas to SCE&G to supply certain electric generation
      requirements and to serve SCE&G’s retail gas customers.  SCE&G
      had approximately $2.0 million payable to CGTC for transportation services
      at
      June 30, 2007 and $1.9 million payable at December 31, 2006.


Table
          of Contents


SCE&G
      purchases natural gas and related pipeline capacity from SCANA Energy
      Marketing, Inc. (SEMI) to supply its Jasper County Electric Generating
      Station and to serve its retail gas customers.  Such purchases totaled
      $47.4 million and $111.9 million for the three and six months ended June 30,
      2007, respectively, and totaled $16.3 million and $23.3 million for the three
      and six months ended June 30, 2006, respectively. SCE&G’s payables to SEMI
      for such purposes were $19.1 million at June 30, 2007 and $15.4 million at
      December 31, 2006.





Total
      interest expense, based on market interest rates, associated with the Company’s
      borrowings from affiliated companies was $1.3 million and $2.2 million for
      the
      three and six months ended June 30, 2007, respectively.  Total
      interest expense for the three and six months ended June 30, 2006 was not
      significant.  Total interest income from investments with affiliated
      companies for the three and six months ended June 30, 2007 and 2006 also was
      not
      significant.  At June 30, 2007 and December 31, 2006, SCE&G owed
      an affiliate $75 million arising from advances from a consolidated cash
      management utility money pool.





SCE&G
      holds equity-method investments in two partnerships involved in converting
      coal
      to synthetic fuel. SCE&G’s receivables from these affiliated companies were
      $28.4 million at June 30, 2007 and $31.8 million at December 31, 2006. 
SCE&G’s payables to these affiliated companies were $26.6 million at June
      30, 2007 and $26.6 million at December 31, 2006.




SCE&G
      purchases shaft horsepower
      from a cogeneration facility.  The facility is owned by a limited
      liability company (LLC) in which SCANA holds an equity-method
      investment.  SCE&G’s payables to the LLC were $2.4 million at June
      30, 2007 and $2.5 million at December 31, 2006.  SCE&G purchased
      $6.1 million and $13.4 million of shaft horsepower from the LLC for the three
      and six months ended June 30, 2007, respectively, and purchased $6.4 million
      and
      $12.7 million of shaft horsepower from the LLC for the three and six months
      ended June 30, 2006, respectively.





D.      Pension
      and Other Postretirement Benefit Plans





Components
      of net periodic benefit income or cost recorded by the Company were as
      follows:





Pension
                Benefits
            
            Other
                Postretirement BenefitsThree
                months ended June 30,
            
            2007
            
            2006
            
            2007
            
            2006Millions
                  of dollarsService
                  cost
            
            $
            3.5
            
            $
            3.5
            
            $
            1.2
            
            $
            1.2Interest
                  cost
            
            
            10.4
            
            
            9.9
            
            
            3.0
            
            
            2.8Expected
                  return on assets
            
            
            (20.1
            )
            
            (18.8
            )
            
            -
            
            
            -Prior
                  service cost amortization
            
            
            1.7
            
            
            1.7
            
            
            0.3
            
            
            0.2Transition
                  obligation amortization
            
            
            -
            
            
            0.1
            
            
            0.2
            
            
            0.2Amortization
                  of actuarial loss
            
            
            -
            
            
            0.2
            
            
            0.3
            
            
            0.4Amount
                  attributable to Company affiliates
            
            
            (0.6
            )
            
            (0.6
            )
            
            (1.3
            )
            
            (1.3
            )Net
                  periodic benefit (income) cost
            
            $
            (5.1
            )
            $
            (4.0
            )
            $
            3.7
            
            $
            3.5





Pension
                Benefits
            
            Other
                Postretirement BenefitsSix
                months ended June 30,
            
            2007
            
            2006
            
            2007
            
            2006Millions
                  of dollarsService
                  cost
            
            $
            7.0
            
            $
            7.0
            
            $
            2.4
            
            $
            2.4Interest
                  cost
            
            
            20.7
            
            
            19.8
            
            
            6.0
            
            
            5.6Expected
                  return on assets
            
            
            (40.2
            )
            
            (37.6
            )
            
            -
            
            
            -Prior
                  service cost amortization
            
            
            3.4
            
            
            3.4
            
            
            0.6
            
            
            0.4Transition
                  obligation amortization
            
            
            -
            
            
            0.2
            
            
            0.4
            
            
            0.4Amortization
                  of actuarial loss
            
            
            -
            
            
            0.4
            
            
            0.6
            
            
            0.7Amount
                  attributable to Company affiliates
            
            
            (1.1
            )
            
            (1.2
            )
            
            (2.7
            )
            
            (2.6
            )Net
                  periodic benefit (income) cost
            
            $
            (10.2
            )
            $
            (8.0
            )
            $
            7.3
            
            $
            6.9





E.       New
      Accounting Matters





SFAS
      159,
*“The Fair Value Option for Financial Assets and Financial Liabilities,”*
      was issued in February 2007. SFAS 159 allows entities to measure at fair value
      many financial instruments and certain other assets and liabilities that are
      not
      otherwise required to be measured at fair value. SFAS 159 is effective for
      fiscal years beginning after November 15, 2007. The Company has not determined
      what impact, if any, that adoption will have on the Company’s results of
      operations, cash flows or financial position.


Table
          of Contents





SFAS
      157,
*“Fair Value Measurements,”* was issued in September 2006.  SFAS 157
      establishes a framework for measuring fair value to increase the consistency
      and
      comparability in fair value measurements.  The Company will adopt SFAS 157
      in the first quarter of 2008, and has not determined what impact, if any, that
      adoption will have on the Company’s results of operations, cash flows or
      financial position.





FIN
      48,
“*Accounting for Uncertainty in Income Taxes,”*clarifies the accounting
      for uncertainty in income taxes recognized in an enterprise’s financial
      statements in accordance with SFAS 109, *“Accounting for Income Taxes.”*FIN 48 prescribes financial statement recognition threshold and measurement
      attributes for tax positions taken or expected to be taken in tax returns.
      FIN
      48 also provides guidance on derecognition, classification, interest and
      penalties, accounting in interim periods, disclosure and transition. The Company
      adopted FIN 48 in the first quarter of 2007.  The impact on the
      Company’s results of operations, cash flows or financial position is discussed
      at Note 1F.




FASB
      Staff Position (FSP) AUG AIR-1 *“Accounting for Planned Major Maintenance
      Activities,”* amended APB 28, “*Interim Financial Reporting,*” to
      prohibit the use of the accrue-in-advance method of accounting for planned
      major
      maintenance.  As disclosed in Note 1A, SCE&G has received specific
      SCPSC orders providing for use of accrue-in-advance accounting for certain
      planned major maintenance activities. Accordingly, SCE&G will continue to
      follow accrue-in-advance accounting as allowed under SFAS 71 for these
      activities. The Company’s adoption of FSP AUG AIR-1 in the first quarter of 2007
      had no impact on the Company’s results of operations, cash flows or financial
      position.





F.       Income
      Taxes





The
      Company is included in the  consolidated federal income tax return of
      SCANA Corporation (SCANA) and files in various state and local
      jurisdictions.  The Internal Revenue Service (IRS) has completed
      examinations of SCANA’s federal returns through 2004, and SCANA’s
      federal tax returns through 2001 are closed for additional
      assessment.  On July 30, 2007, the statute of limitations for the 2002
      federal return expired, but no material changes resulted.  With a few
      exceptions, the Company is no longer subject to state and local income tax
      examinations by tax authorities for years before 2003.  The IRS has
      completed the examination of S. C. Coaltech No. 1 LP., a synthetic fuel
      partnership in which SCE&G has an interest, for the 2004 tax
      year.  SCE&G does not anticipate that any adjustments from the
      examination will have a material impact on the earnings, cash flows or the
      financial position of SCE&G.  SCE&G continues to believe that
      all of its synthetic fuel tax credits have been properly claimed.





In
      connection with the initial adoption of FIN 48 effective January 1, 2007,
      SCE&G removed $15 million of previously recognized tax benefits from its
      balance sheet.  Because regulatory liabilities had been recorded for
      these previously recognized tax benefits under the provisions of SFAS 71, these
      benefits had never been recognized in SCE&G’s earnings or retained
      earnings.  As a result, the initial adoption of FIN 48 had no effect
      on SCE&G’s equity.  The total amount of unrecognized tax benefits
      that, if recognized, would affect the effective tax rate is $15
      million.  Because the benefits would be amortized into earnings over a
      number of years under SFAS 71, the impact on any individual year’s effective tax
      rate would be immaterial.  No material changes in the status of our
      tax positions have occurred subsequent to adoption.





The
      Company recognizes interest accrued related to unrecognized tax benefits within
      interest expense and recognizes tax penalties within other
      expenses.  Through June 30, 2007, the Company has not accrued any
      significant amount of interest or tax penalties.





G.      Accumulated
      Other Comprehensive Loss





Accumulated
      other comprehensive loss,
      comprised of the deferred cost of employee benefit plans, totaled $6.9 million
      as of June 30, 2007 and December 31, 2006.





2.       RATE
      AND OTHER REGULATORY MATTERS





Electric





On
      June
      15, 2007 SCE&G filed an application with the SCPSC requesting a 6.75%
      increase in retail electric rates.  The application, among other
      things, seeks recovery of costs incurred to perform mandatory environmental
      upgrades to SCE&G’s generating plants.  SCE&G’s application is
      expected to be heard by the SCPSC in November 2007.  If approved, the
      new rates would be effective in January 2008.





SCE&G's
      rates are established using a cost of fuel component approved by the SCPSC
      which
      may be modified periodically to reflect changes in the price of fuel purchased
      by SCE&G.  In May 2006 SCE&G agreed to spread the recovery of
      previously under-collected fuel costs of $38.5 million over a two-year
      period.




Table
          of Contents


Gas





On
      June
      15, 2007 SCE&G filed an application with the SCPSC requesting an increase in
      retail natural gas rates of 1.3% under the terms of the Natural Gas Rate
      Stabilization Act (Stabilization Act).  The Stabilization Act is
      designed to reduce the volatility of costs charged to customers by allowing
      for
      more timely recovery of the costs that regulated utilities incur related to
      natural gas service infrastructure.  The SCPSC is expected to review
      SCE&G’s filing in October 2007.  If approved, the rate adjustment
      would be implemented with the first billing cycle in November 2007.





In
      September 2006, the SCPSC approved an increase in retail natural gas rates
      of
      3.2% under the terms of the Stabilization Act.  The rate adjustment
      was effective with the first billing cycle in November 2006.





SCE&G's
      rates are established using a cost of gas component approved by the SCPSC in
      October 2006 which authorized SCE&G to adjust its cost of gas on a monthly,
      rather than an annual, basis beginning in December 2006.  The cost of
      gas adjustment is based on a twelve-month rolling average.





3.      LONG-TERM
      DEBT





Substantially
      all of the Company’s electric utility plant is pledged as collateral in
      connection with long-term debt.





4.      FINANCIAL
      INSTRUMENTS





The
      Company utilizes various financial derivatives, including those designated
      as
      cash flow hedges related to natural gas. The Company also utilizes swap
      agreements to manage interest rate risk. These transactions are more fully
      described in Note 9 to the consolidated financial statements in SCE&G’s
      Annual Report on Form 10-K for the year ended December 31, 2006.





The
      Company’s regulated gas operations hedge natural gas purchasing activities using
      over-the-counter options and swaps and New York Mercantile Exchange (NYMEX)
      futures and options. The Company’s tariffs include a purchased gas adjustment
      (PGA) clause that provides for the recovery of actual gas costs incurred. The
      SCPSC has ruled that the results of these hedging activities are to be included
      in the PGA. As such, costs of related derivatives utilized to hedge gas
      purchasing activities are recoverable through the weighted average cost of
      gas
      calculation. The offset to the change in fair value of these derivatives is
      recorded as a regulatory asset or liability.





5.       COMMITMENTS
      AND CONTINGENCIES





Reference
      is made to Note 10 to the consolidated financial statements appearing in
      SCE&G’s Annual Report on Form 10-K for the year ended December 31, 2006.
      Commitments and contingencies at June 30, 2007 include the
      following:





A.      Nuclear
      Insurance





The
      Price-Anderson Indemnification Act deals with public liability for a nuclear
      incident and establishes the liability limit for third-party claims associated
      with any nuclear incident at $10.5 billion. Each reactor licensee is currently
      liable for up to $100.6 million per reactor owned for each nuclear incident
      occurring at any reactor in the United States, provided that not more than
      $15
      million of the liability per reactor would be assessed per year. SCE&G’s
      maximum assessment, based on its two-thirds ownership of Summer Station, would
      be $67.1 million per incident, but not more than $10 million per
      year.




SCE&G
      currently maintains policies (for itself and on behalf of Santee Cooper, the
      one-third owner of Summer Station) with Nuclear Electric Insurance Limited.
      The
      policies, covering the nuclear facility for property damage, excess property
      damage and outage costs, permit retrospective assessments under certain
      conditions to cover insurer’s losses. Based on the current annual premium,
      SCE&G’s portion of the retrospective premium assessment would not exceed
      $14.1 million.





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


Table
          of Contents





B.     
      Environmental




In
      March
      2005, the United States Environmental Protection Agency (EPA) issued a final
      rule known as the Clean Air Interstate Rule (CAIR). CAIR requires the District
      of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide
      and sulfur dioxide emissions in order to attain mandated state levels. SCE&G
      has petitioned the United States Court of Appeals for the District of Columbia
      Circuit to review CAIR. Several other electric utilities have filed separate
      petitions. The petitioners seek a change in the method CAIR uses to allocate
      sulfur dioxide emission allowances to a method the petitioners believe is more
      equitable. The Company believes that installation of additional air quality
      controls will be needed to meet the CAIR requirements, although compliance
      plans and cost to comply with the rule have not been determined. Such costs
      will
      be material and are expected to be recoverable through rates.





In
      March
      2005, the EPA issued a final rule establishing a mercury emissions cap and
      trade
      program for coal-fired power plants that requires limits to be met in two
      phases, in 2010 and 2018. Although the Company expects to be able to meet
      the  Phase I limits through those measures it already will be taking to
      meet its CAIR obligations, it is uncertain as to how the Phase II limits will
      be
      met. Assuming Phase II limits remain unchanged, installation of additional
      air
      quality controls likely will be required to comply with the rule’s Phase II
      mercury emission caps. Final compliance plans and costs to comply with the
      rule
      are still under review. Such costs will be material and are expected to be
      recoverable through rates.





SCE&G
      has been named, along with 53 others, by the EPA as a potentially responsible
      party (PRP) at the Alternate Energy Resources, Inc. (AER) Superfund site located
      in Augusta, Georgia.  The EPA placed the site on the National Priorities
      List on April 19, 2006. AER conducted hazardous waste storage and treatment
      operations from 1975 to 2000, when the site was abandoned.  While
      operational, AER processed fuels from waste oils, treated industrial coolants
      and oil/water emulsions, recycled solvents and blended hazardous waste
      fuels.  During that time, SCE&G occasionally used AER for the
      processing of waste solvents, oily rags and oily wastewater. The EPA and the
      State of Georgia have documented that a release or releases have occurred at
      the
      site leading to contamination of groundwater, surface water and soils.  The
      EPA and the State of Georgia have conducted a preliminary assessment and site
      inspection. The site has not been remediated nor has a clean-up cost been
      estimated.  Although a basis for the allocation of clean-up costs among the
      PRPs is unclear, SCE&G does not believe that its involvement at this site
      would result in an allocation of costs that would have a material adverse impact
      on its results of operations, cash flows or financial condition. Any cost
      allocated to SCE&G arising from the remediation of this site, net of
      insurance recoveries, if any, is expected to be recoverable through
      rates.





SCE&G
      has been named, along with 29 others, by the EPA as a PRP at the Carolina
      Transformer Superfund site located in Fayetteville, North Carolina.  The
      Carolina Transformer Company (CTC) conducted an electrical transformer
      rebuilding and repair operation at the site from approximately 1959 to
      1986.  During that time, SCE&G occasionally used CTC for the repair of
      existing transformers, purchase of new transformers and sale of used
      transformers.  In 1984, the EPA initiated a remediation of PCB-contaminated
      soil and groundwater at the site.  The EPA reports that it has spent $36
      million to date.  SCE&G does not believe that its involvement at this
      site would result in an allocation of costs that would have a material adverse
      impact on its results of operations, cash flows or financial condition. Any
      cost
      allocated to SCE&G arising from the remediation of this site, net of
      insurance recoveries, if any, is expected to be recoverable through
      rates.





SCE&G
      maintains an environmental assessment program to identify and evaluate its
      current and former MGP sites that could require environmental clean-up. As
      site
      assessments are initiated, estimates are made of the amount of expenditures,
      if
      any, deemed necessary to investigate and remediate each site. These estimates
      are refined as additional information becomes available; therefore, actual
      expenditures could differ significantly from the original estimates. Amounts
      estimated and accrued to date for site assessments and clean-up relate solely
      to
      regulated operations.  SCE&G defers site assessment and clean-up costs
      and recovers them through rates (see Note 1). Deferred amounts, net of amounts
      previously recovered through rates and insurance settlements, totaled $17.2
      million at June 30, 2007.  The deferral includes the estimated costs
      associated with the following matters.





SCE&G
      owns a decommissioned MGP site in the Calhoun Park area of Charleston,
      South Carolina. SCE&G anticipates that remediation for contamination at the
      site will be completed in late 2007, with certain monitoring and retreatment
      activities continuing through 2012. As of June 30, 2007, SCE&G had spent
      $22.3 million to remediate the site and expects to spend an additional $1.0
      million prior to entering a monitoring and reporting stage. In addition, the
      National Park Service of the Department of the Interior made an initial demand
      to SCE&G for payment of $9.1 million for certain costs and damages relating
      to this site. SCE&G expects to recover any cost arising from the remediation
      of this site through rates.





SCE&G
      owns three other decommissioned MGP sites in South Carolina which contain
      residues of by-product chemicals. One of the sites has been remediated and
      will
      undergo routine monitoring until released by the South Carolina Department
      of
      Health and Environmental Control (DHEC). The other sites are currently being
      investigated under work plans approved by DHEC. SCE&G anticipates that major
      remediation activities for the three sites will be completed by 2011. As of
      June
      30, 2007, SCE&G has spent $4.8 million related to these three sites, and
      expects to spend an additional $11.2 million.  SCE&G expects to
      recover any cost arising from the remediation of these sites through
      rates.




C.     Claims
      and Litigation





In
      August
      2003, SCE&G was served as a co-defendant in a purported class action lawsuit
      styled as Collins v. Duke Energy Corporation, Progress Energy Services Company,
      and South Carolina Electric & Gas Company in South Carolina's Circuit
      Court of Common Pleas for the Fifth Judicial Circuit.  The plaintiffs
      subsequently dismissed defendants Duke Energy and Progress Energy and proceeded
      against SCE&G only. The plaintiffs sought damages for the alleged improper
      use of electric transmission and distribution easements but did not assert
      a
      dollar amount for their claims. Specifically, the plaintiffs alledged that
      the
      licensing of attachments on electric utility poles, towers and other facilities
      to nonutility third parties or telecommunication companies for other than the
      electric utility’s internal use along the electric transmission and distribution
      line rights-of-way constituted a trespass. On July 20, 2007, Plaintiffs’ counsel
      filed a Stipulation of Dismissal Without Prejudice with the Lexington County
      Clerk of Court’s Office.  This case can be re-filed; however, SCANA
      and SCE&G believe that the resolution of these claims will not have a
      material adverse impact on their results of operations, cash flows or financial
      condition.





In
      May
      2004, the Company was served with a purported class action lawsuit styled as
      Douglas E. Gressette, individually and on behalf of other persons similarly
      situated v. South Carolina Electric & Gas Company and SCANA Corporation. The
      case was filed in South Carolina’s Circuit Court of Common Pleas for the Ninth
      Judicial Circuit. The plaintiff alleges the Company made improper use of certain
      easements and rights-of-way by allowing fiber optic communication lines and/or
      wireless communication equipment to transmit communications other than the
      Company’s electricity-related internal communications.  The plaintiff
      asserted causes of action for unjust enrichment, trespass, injunction and
      declaratory judgment. The plaintiff did not assert a specific dollar amount
      for
      the claims. The Company believes its actions are consistent with governing
      law
      and the applicable documents granting easements and rights-of-way. The Circuit
      Court granted the Company’s motion to dismiss and issued an order dismissing the
      case in June 2005. The plaintiff appealed to the South Carolina Supreme Court.
      The Supreme Court overruled the Circuit Court in October 2006 and returned
      the
      case to the Circuit Court for further consideration.  In July 2007, the
      Circuit Court issued a ruling that limits the plaintiff’s purported class to
      owners of easements situated in Charleston County, South
      Carolina.  The plaintiff has appealed this ruling to the South
      Carolina Court of Appeals.  It is anticipated that this case may not
      go to trial before 2008.  The Company will continue to mount a
      vigorous defense and believes that the resolution of these claims will not
      have
      a material adverse impact on its results of operations, cash flows or financial
      condition.





A
      complaint was filed in October 2003 against SCE&G by the State of South
      Carolina alleging that SCE&G violated the Unfair Trade Practices Act by
      charging municipal franchise fees to some customers residing outside a
      municipality’s limits. The complaint sought restitution to all affected
      customers and penalties of up to $5,000 for each separate violation. The claim
      against SCE&G has been settled by an agreement between the parties, and the
      settlement has been approved by South Carolina’s Circuit Court of Common Pleas
      for the Fifth Judicial Circuit. In addition, SCE&G filed a petition with the
      SCPSC in October 2003 pursuant to S. C. Code Ann. R.103-836. The petition
      requests that the SCPSC exercise its jurisdiction to investigate the operation
      of the municipal franchise fee collection requirements applicable to SCE&G’s
      electric and gas service, to approve SCE&G’s efforts to correct any past
      franchise fee billing errors, to adopt improvements in the system which will
      reduce such errors in the future, and to adopt any regulation that the SCPSC
      deems just and proper to regulate the franchise fee collection process. A
      hearing on this petition has not been scheduled. The Company believes that
      the
      resolution of these matters will not have a material adverse impact on its
      results of operations, cash flows or financial condition.




The
      Company is also engaged in various other claims and litigation incidental to
      its
      business operations which management anticipates will be resolved without a
      material adverse impact on the Company’s results of operations, cash flows or
      financial condition.


Table
          of Contents





6.     
       SEGMENT OF BUSINESS INFORMATION





The
      Company’s reportable segments are listed in the following table. The Company
      uses operating income to measure profitability for its regulated operations.
      Therefore, earnings available to the common shareholder are not allocated to
      the
      Electric Operations and Gas Distribution segments. Intersegment revenues were
      not significant. All Other includes equity method investments.





Earnings
                (Loss)Operating
            
            Available
                toExternal
            
            Income
            
            Common
            
            SegmentMillions
                of Dollars
            
            Revenue
            
            (Loss)
            
            Shareholder
            
            Assets*Three
                  Months Ended June 30, 2007*Electric
                  Operations
            
            $
            472
            
            $
            111
            
            
            n/aGas
                  Distribution
            
            
            103
            
            
            -
            
            
            n/aAll
                  Other
            
            
            -
            
            
            -
            
            
            (4
            )Adjustments/Eliminations
            
            
            -
            
            
            (2
            )
            
            56Consolidated
                  Total
            
            $
            575
            
            $
            109
            
            $
            52





*Six
                  Months Ended June 30, 2007*Electric
                  Operations
            
            $
            917
            
            $
            166
            
            
            n/a
            
            $
            5,746Gas
                  Distribution
            
            
            292
            
            
            27
            
            
            n/a
            
            
            463All
                  Other
            
            
            -
            
            
            -
            
            $
            (10
            )
            
            -Adjustments/Eliminations
            
            
            -
            
            
            (3
            )
            
            97
            
            
            1,501Consolidated
                  Total
            
            $
            1,209
            
            $
            190
            
            $
            87
            
            $
            7,710





*Three
                  Months Ended June 30, 2006*Electric
                  Operations
            
            $
            464
            
            $
            119
            
            
            n/aGas
                  Distribution
            
            
            89
            
            
            (3
            )
            
            n/aAll
                  Other
            
            
            -
            
            
            -
            
            $
            (4
            )Adjustments/Eliminations
            
            
            -
            
            
            (3
            )
            
            55Consolidated
                  Total
            
            $
            553
            
            $
            113
            
            $
            51





*Six
                  Months Ended June 30, 2006*Electric
                  Operations
            
            $
            864
            
            $
            210
            
            
            n/a
            
            $
            5,458Gas
                  Distribution
            
            
            281
            
            
            16
            
            
            n/a
            
            
            404All
                  Other
            
            
            -
            
            
            -
            
            $
            (6
            )
            
            5Adjustments/Eliminations
            
            
            -
            
            
            (10
            )
            
            104
            
            
            1,527Consolidated
                  Total
            
            $
            1,145
            
            $
            216
            
            $
            98
            
            $
            7,394


Table
          of Contents


**ITEM
      2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
      CONDITION**


**AND
      RESULTS OF OPERATIONS**





**SOUTH
      CAROLINA ELECTRIC & GAS COMPANY**





The
      following discussion should be read in conjunction with Management’s Discussion
      and Analysis of Financial Condition and Results of Operations appearing in
      South
      Carolina Electric & Gas Company’s (SCE&G, and together with its
      consolidated affiliates, the Company) Annual Report on Form 10-K for the year
      ended December 31, 2006.





**RESULTS
      OF OPERATIONS**


**FOR
      THE THREE AND SIX MONTHS ENDED JUNE 30, 2007**


**AS
      COMPARED TO THE CORRESPONDING PERIODS IN 2006**





Net
      Income





Net
      income was as follows:





Second
                Quarter
            Year
                to Date2007
            
            2006
            
            
            2007
            
            2006Net
                  income
            $
            53.7
            
            $
            52.5
            
            $
            91.1
            
            $
            102.0





*Second
      Quarter*





Net
      income increased primarily due to a higher gas margin of $3.2 million and a
      higher electric margin of $1.8 million, partially offset by increased incentive
      compensation and other benefit costs of $2.5 million, Accelerated depreciation
      on the Lake Murray back-up dam and recognition of synthetic fuel tax credits
      and
      related items had no effect on net income, as discussed at Income Taxes -
*Recognition of Synthetic Fuel Tax Credits*.





*Year
      to Date*





Net
      income decreased due to  increased electric generation, transmission
      and distribution expenses of $5.2 million, increased incentive compensation
      and
      other benefit costs of $4.7 million, increased depreciation expense of $3.3
      million, increased property and other taxes of $2.2 million and the recognition
      in 2006 of the cumulative effect of an accounting change resulting from SCANA’s
      adoption of Statement of Financial Accounting Standards  123(R),
*“Share-Base Payment,”* of $3.8 million, partially offset by an increase
      in gas margin of $8.0 million and an increase in electric margin of $1.2
      million.  Accelerated depreciation on the Lake Murray back-up dam and
      recognition of synthetic fuel tax credits and related items had no effect on
      net
      income, as discussed at Income Taxes - *Recognition of Synthetic Fuel Tax
      Credits*.





**Dividends
      Declared**





The
      Company’s Board of Directors has declared the following dividends on common
      stock held by SCANA Corporation (SCANA) during 2007:





Declaration
                Date
            Amount
            Quarter
                Ended
            Payment
                DateFebruary
                  15, 2007
            $36.0
                  million
            March
                  31, 2007
            April
                  1, 2007April
                  26, 2007
            $39.7
                  million
            June
                  30, 2007
            July
                  1, 2007August
                  2, 2007
            $39.7
                  million
            September
                  30, 2007
            October
                  1, 2007





**Electric
      Operations**





Electric
      Operations is comprised of the electric operations of SCE&G, South Carolina
      Generating Company, Inc. (GENCO) and South Carolina Fuel Company, Inc.
      (SCFC).  Electric operations sales margin (including transactions with
      affiliates) was as follows:





Second
                Quarter
            
            
            Year
                To DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                  revenues
            
            $
            472.0
            
            1.7
            %
            $
            464.3
            
            $
            916.6
            
            
            6.1
            %
            $
            863.9Less:
                  Fuel used in electric generation
            
            
            152.9
            
            4.3
            %
            
            146.6
            
            
            308.8
            
            
            16.9
            %
            
            264.1Purchased power
            
            
            6.6
            
            (19.5)
            %
            
            8.2
            
            
            18.0
            
            
            51.3
            %
            
            11.9Margin
            
            $
            312.5
            
            1.0
            %
            $
            309.5
            
            $
            589.8
            
            
            0.3
            %
            $
            587.9




Table
          of Contents





*Second
      Quarter*





Margin
      increased by $11.1 million due to customer growth and usage.  This
      increase was partially offset by $5.6 million due to lower off-system
      sales.





*Year
      to Date*





Margin
      increased by $19.1 million due to customer growth and usage.  This
      increase was partially offset by $16.3 million due to lower off-system
      sales.





**Gas
      Distribution**





Gas
      Distribution is comprised of the local distribution operations of SCE&G. Gas
      distribution sales margin (including transactions with affiliates) was as
      follows:





Second
                Quarter
            
            
            Year
                To DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Operating
                  revenues
            
            $
            103.2
            
            16.2
            %
            $
            88.8
            
            $
            292.3
            
            
            3.8
            %
            $
            281.5Less:
                  Gas purchased for resale
            
            
            80.9
            
            13.0
            %
            
            71.6
            
            
            220.3
            
            
            (2.1
            )%
            
            225.1Margin
            
            $
            22.3
            
            29.7
            %
            $
            17.2
            
            $
            72.0
            
            
            27.7
            %
            $
            56.4





*Second
      Quarter*





Margin
      increased by $3.3 million due to
      the Public Service Commission of South Carolina (SCPSC)-approved increase to
      retail gas base rates effective with the first billing cycle in November 2006
      and by $1.9 million due to customer growth.





*Year
      to Date*





Margin
      increased by $10.8 million due to an SCPSC-approved increase in retail gas
      base
      rates and by $2.2 million due to customer growth.




**Other
      Operating Expenses**





Other
      operating expenses were as follows:





Second
                Quarter
            
            
            Year
                To DateMillions
                of dollars
            
            
            2007
            
            %
                Change
            
            
            2006
            
            
            2007
            
            %
                Change
            
            
            2006Other
                  operation and maintenance
            
            $
            116.9
            
            2.7
            %
            $
            113.8
            
            $
            246.0
            
            
            7.6
            %
            $
            228.6Depreciation
                  and amortization
            
            
            74.0
            
            12.8
            %
            
            65.6
            
            
            153.2
            
            
            17.8
            %
            
            130.1Other
                  taxes
            
            
            35.1
            
            3.2
            %
            
            34.0
            
            
            72.5
            
            
            5.1
            %
            
            69.0





*Second
      Quarter*





Other
      operation and maintenance expenses increased by $4.2 million due to higher
      incentive compensation and other benefit costs.  This increase was
      partially offset by lower costs related to injuries and damages claims of $1.2
      million.  Depreciation and amortization expense increased by $5.9
      million due to lower estimated phase-out of synthetic fuel tax credits related
      to the back-up dam at Lake Murray (see Income Taxes-*Recognition of Synthetic
      Fuel Tax Credits*) and by $2.5 million due to net property
      additions.  Other taxes increased due to higher property
      taxes.





*Year
      to Date*





Other
      operation and maintenance expenses increased by $8.5 million due to higher
      electric generation, transmission and distribution expenses and by $7.6 million
      due to higher incentive compensation and other benefit
      costs.  Depreciation and amortization expense increased by $17.8
      million due to lower estimated phase-out of synthetic fuel tax credits related
      to the back-up dam at Lake Murray (see Income Taxes-*Recognition of Synthetic
      Fuel Tax Credits*) and by $5.4 million due to net property
      additions.  Other taxes increased due to higher property
      taxes.


Table
          of Contents


**Other
      Income (Expense*)***





Other
      income (expense) includes the results of certain incidental (non-utility)
      activities. Other income (expense) declined in 2007 compared to 2006
      primarily due to lower carrying cost recovery recognition on the unrecovered
      balance of the Lake Murray back-up dam project.





**Income
      Taxes**





Income
      tax expense decreased primarily due to changes in operating income and due
      to
      the recognition of $18.5 million in synthetic fuel tax credits during the first
      half of 2007 compared to $8.8 million during the same period in
      2006.





*Recognition
      of Synthetic Fuel Tax Credits*





SCE&G
      holds equity-method investments in two partnerships involved in converting
      coal
      to synthetic fuel, the use of which fuel qualifies for federal income tax
      credits. Under an accounting methodology approved by the SCPSC in a January
      2005
      order, construction costs related to the Lake Murray back-up dam project are
      recorded in utility plant in service in a special dam remediation account
      outside of rate base, and depreciation is being recognized against the balance
      in this account on an accelerated basis, subject to the availability of the
      synthetic fuel tax credits.





The
      level
      of depreciation expense and related tax benefit recognized in the income
      statement is equal to the available synthetic fuel tax credits, less partnership
      losses and other expenses, net of taxes. As a result, the balance of unrecovered
      costs in the dam remediation account declines as accelerated depreciation is
      recorded. Although these entries collectively have no impact on consolidated
      net
      income, they can have a significant impact on individual line items within
      the
      income statement. The accelerated depreciation, synthetic fuel tax credits,
      partnership losses and the income tax benefit arising from such losses
      recognized by SCE&G during the three and six months ended June 30, 2007 and
      2006 are as follows:





Second
                Quarter
            
            Year
                to DateMillions
                of dollars
            
            
            2007
            
            
            2006
            
            2007
            
            2006Depreciation
                  and amortization expense
            
            $
            (7.1
            )
            $
            (1.2
            )
            $
            (19.1)
            
            $
            (1.4
            )Income
                  tax benefits:From
                  synthetic fuel tax credits
            
            
            6.8
            
            
            3.3
            
            
            17.7
            
            
            6.6From
                  accelerated depreciation
            
            
            2.7
            
            
            0.5
            
            
            7.3
            
            
            0.6From
                  partnership losses
            
            
            1.5
            
            
            1.5
            
            
            3.6
            
            
            3.5Total
                  income tax benefits
            
            
            11.0
            
            
            5.3
            
            
            28.6
            
            
            10.7Losses
                  from Equity Method Investments
            
            
            (3.9
            )
            
            (4.1
            )
            
            (9.5)
            
            
            (9.3
            )Impact
                  on Net Income
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            -





Depreciation
      on the Lake Murray back-up dam remediation account will be matched to
      available synthetic fuel tax credits on a quarterly basis until all of the
      available synthetic fuel tax credits have been utilized.  The
      synthetic fuel tax credit program expires at the end of 2007.





The
      availability of the synthetic fuel tax credits is dependent on several factors,
      one of which is the average annual domestic wellhead price per barrel of crude
      oil as published by the U.S. Government. Under a phase-out provision included
      in
      the program, if the domestic wellhead reference price of oil per barrel for
      a
      given year is below an inflation-adjusted benchmark range for that year, all
      of
      the synthetic fuel tax credits that have been generated in that year would
      be
      available for use. If that price is above the benchmark range, none of the
      tax
      credits would be available. If that price falls within the benchmark range,
      a
      calculated portion of the credits would be available.





The
      benchmark price range for 2006, published in April 2007, was $55 to $69 per
      barrel, resulting in a phase-out of 33 percent for 2006.  SCE&G’s
      analysis indicates that the available synthetic fuel tax credits for
      2007 also are likely to be impacted by the phase-out calculation. As such,
      through June 2007 the Company recorded synthetic fuel tax credits and applied
      those credits to allow the recording of accelerated depreciation related to
      the
      balance in the dam remediation project account based on an estimate that only
      74.5 percent of credits generated in 2007 will be available (phase-out of 25.5
      percent). The Company cannot predict what impact, if any, the price of oil
      may
      have on the Company’s ability to earn and utilize synthetic fuel tax credits in
      the future. However, there is significant uncertainty as to the continued
      availability of the credits in 2007. The availability of these synthetic fuel
      tax credits is also subject to coal availability and other operational risks
      related to the generating plants.




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The
      Company does not expect available credits to be sufficient to fully recover
      the
      construction costs of dam remediation, and the total unrecovered costs at the
      end of 2007 may be significant. To the extent that available credits are not
      sufficient to fully recover the construction costs of the dam remediation,
      regulatory action to allow recovery of those remaining costs will likely be
      sought. As of June 30, 2007, remaining unrecovered costs, based on management’s
      recording of accelerated depreciation and related tax benefits, were $54.0
      million.





**LIQUIDITY
      AND CAPITAL RESOURCES**





The
      Company anticipates that its contractual cash obligations will be met through
      internally generated funds, the incurrence of additional short- and long-term
      indebtedness and sales of equity securities. The Company expects that it has
      or
      can obtain adequate sources of financing to meet its projected cash requirements
      for the foreseeable future. The Company’s ratios of earnings to fixed charges
      for the six and 12 months ended June 30, 2007 were 2.63 and 3.09,
      respectively.  The Company’s ratios of earnings to combined fixed
      charges and preference dividends for the same periods were 2.44 and 2.87,
      respectively.





The
      Company’s
      cash requirements arise primarily from its operational needs, funding its
      construction programs and payment of dividends to SCANA. The ability of the
      Company to replace existing plant investment, to expand to meet future demand
      for electricity and gas and to install equipment necessary to comply with
      environmental regulations will depend upon its ability to attract the necessary
      financial capital on reasonable terms. SCE&G recovers the costs of providing
      services through rates charged to customers. Rates for regulated services are
      generally based on historical costs. As customer growth and inflation occur
      and
      SCE&G continues its ongoing construction program, SCE&G expects to seek
      increases in rates. The Company’s future financial position and results of
      operations will be affected by SCE&G’s ability to obtain adequate and timely
      rate and other regulatory relief, if requested.





SCE&G
      expects to add additional base load electric generation in the 2015 to 2016
      timeframe.  Based on an evaluation of alternatives, SCE&G and
      Santee Cooper, a state-owned utility in South Carolina (joint owners of Summer
      Station) have selected the Summer Station site as the preferred site for new
      nuclear generation. Due to the significant lead time required for construction
      of nuclear generation, the joint owners are preparing an application to the
      Nuclear Regulatory Commission (NRC) for a combined construction and operating
      license (COL) that would cover two new nuclear units. The COL application,
      which
      is expected to be completed and filed in 2007, would be reviewed by the NRC
      for
      an estimated three years. While SCE&G’s current plans are to pursue the
      development of one or both of these nuclear units, these plans will continue
      to
      be influenced by many factors, including NRC licensing attainment, ongoing
      evaluation of relative construction and operating costs, the cost of competing
      fuels, regulatory and environmental requirements and financial market
      conditions.





In
      May 2007, the Base Load Review Act
      (the Act) became law in South Carolina.  This law is intended to allow
      a utility to recover prudently incurred capital and operating costs associated
      with new nuclear or coal-fired base load electric generating facilities larger
      than 350 megawatts.  Based on an application filed by the utility
      under the Act, the SCPSC would review and rule on the prudency of the decision
      to build the plant.  If the decision was found to be prudent, that
      finding would be binding on all future proceedings so long as the plant is
      constructed in accordance with the schedules, estimates and projections set
      forth in the approved application.  In addition, beginning with the
      initial proceeding, the utility would be allowed to file revised rates with
      the
      SCPSC each year to incorporate any nuclear construction work in progress
      incurred.  Requested rate adjustments would be based on the utility’s
      updated cost of debt and capital structure.  The cost of service and
      rate design would be based on the rates approved in the utility’s most recent
      electric rate order.  The utility may choose to file for a
      project-specific return on common equity or use the return from its most recent
      rate proceeding if the proceeding is less than five years old.





The
      Company's issuance of various securities, including short- and long-term debt,
      is subject to customary approval or authorization by state and federal
      regulatory bodies including the SCPSC and Federal Energy Regulatory Commission
      (FERC).





Pursuant
      to Section 204 of the Federal Power Act, SCE&G and GENCO must obtain FERC
      authority to issue short-term debt. Effective February 8, 2006, the FERC has
      authorized SCE&G and GENCO to issue up to $700 million and $100 million,
      respectively, of unsecured promissory notes or commercial paper with maturity
      dates of one year or less. This authorization expires February 7,
      2008.




**ENVIRONMENTAL
      AND REGULATORY MATTERS**





The
      EPA
      has undertaken an aggressive enforcement initiative and the United States
      Department of Justice (DOJ) has brought suit against a number of utilities
      in
      federal court alleging violations of the Clean Air Act (CAA). At least two
      of
      these suits have either been tried or have had substantive motions
      decided—neither favorable to the industry. One of the decisions is not believed
      to be binding as precedent and the other one, described more fully
      below, may be.


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On
      April 2,
      2007, in a unanimous ruling, the U.S. Supreme Court vacated a decision by the
      U.S. Court of Appeals for the Fourth Circuit that effectively halted the EPA
      enforcement action against Duke Energy Corporation (Duke) for allegedly
      performing plant modifications without a required permit.  Such
      modifications for life extension and modernization as performed by Duke and
      other utilities, including SCE&G, were common within the industry. 
Hence this decision may heighten the potential exposure of utilities to
      enforcement actions such as those already brought against Duke and others,
      many
      of which had not proceeded pending this Supreme Court decision.




Although
      the Supreme Court overturned the lower courts’ decisions, some issues were not
      ruled upon and were remanded to the lower courts where they may receive further
      consideration.  Several arguments are expected to continue during the
      remand proceedings. For example, Duke argued that the EPA has taken inconsistent
      positions in its interpretations of “routine maintenance, repair and
      replacement” and is now “retroactively targeting twenty years of accepted
      practice.” The Supreme Court noted that this issue was not addressed by the
      lower court decisions, and, to the extent it is not procedurally foreclosed,
      Duke may raise it on remand.




Prior
      to
      the suits, those utilities had received requests for information under
      Section 114 of the CAA and were issued Notices of Violation. The basis for
      these suits is the assertion by the EPA, under a stringent rule known as New
      Source Review (NSR), that certain maintenance activities undertaken by the
      utilities constitute “major modifications” which would have required the
      installation of costly Best Available Control Technology (BACT). SCE&G and
      GENCO have previously received and responded to Section 114 requests for
      information related to Canadys, Wateree and Williams Stations. The regulations
      under the CAA provide certain exemptions to the definition of “major
      modifications,” including an exemption for routine repair, replacement or
      maintenance. On October 27, 2003, the EPA published a final revised NSR
      rule in the Federal Register with an effective date of December 26, 2003.
      The rule represents an industry-favorable departure from certain positions
      advanced by the federal government in the NSR enforcement initiative. However,
      on motion of several Northeastern states, the United States Circuit Court of
      Appeals for the District of Columbia stayed the effect of the final rule. Even
      with the recent Supreme Court action described above, the ultimate application
      of the final rule to the Company is uncertain. The Company has analyzed each
      of the
      activities covered by the EPA’s requests and believes each of these activities
      is covered by the exemption for routine repair, replacement and maintenance
      under what it believes is a fair reading of both the prior regulation and the
      contested revised regulation. The regulations also provide an exemption for
      an
      increase in emissions resulting from increased hours of operation or production
      rate and from demand growth.





The
      current state of continued DOJ enforcement actions continues to be the subject
      of industry-wide speculation, but it is possible that the EPA will commence
      enforcement actions against SCE&G and GENCO, and the EPA has the authority
      to seek penalties at the rate of up to $27,500 per day for each violation.
      The
      EPA also could seek installation of BACT (or equivalent) at the three plants.
      The Company continues to believe that any enforcement actions relative to the
      Company’s compliance with the CAA would be without merit. The Company has
      completed installation of selective catalytic reactors at Wateree and Williams
      for nitrogen oxides control and is proceeding with plans to install sulfur
      dioxide scrubbers at both of these stations to meet Clean Air Interstate Rule
      (CAIR) regulations. These actions would mitigate many of the concerns with
      NSR.
      SCE&G and GENCO expect to incur capital expenditures totaling approximately
      $450 million over the 2007-2010 period to install this new equipment.
      SCE&G and GENCO also expect to have increased operation and maintenance
      costs related to this equipment of approximately $3.4 million in 2009 and
      $23 million in 2010 and each subsequent year thereafter. To meet compliance
      requirements for the years 2012 through 2016, the Company anticipates additional
      capital expenditures totaling approximately $480 million.





See
      notes
      to the condensed consolidated financial statements for additional information
      related to environmental matters (Note 5B) and regulatory matters (Note
      2).





**ITEM
      3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
      MARKET RISK**





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





Interest
      rate risk - The table below provides information about long-term debt issued
      by
      the Company which is sensitive to changes in interest rates. The table presents
      principal cash flows and related weighted average interest rates by expected
      maturity dates. Fair value represents quoted market prices.





As
                of June 30, 2007
            
            Expected
                MaturityThere-
            
            FairMillions
                of dollars
            2007
            2008
            2009
            2010
            2011
            after
            Total
            ValueLong-Term
                  Debt Issued:Fixed
                  Rate ($)
            3.7
            3.7
            103.7
            10.4
            164.9
            1,667.9
            1,954.3
            2,001.2Average
                  Interest Rate (%)
            7.78
            7.78
            6.18
            6.31
            6.71
            5.83
            5.93
            n/a




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





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Commodity
      price risk - The following table provides information about the Company’s
      financial instruments that are sensitive to changes in natural gas prices.
      Weighted average settlement prices are per 10,000 dekatherms. Fair value
      represents quoted market prices.





Expected
                MaturityFutures
                Contracts - Long
            2007
            2008
            2009Settlement
                  Price (a)
            7.52
            8.63
            9.51Contract
                  Amount (b)
            6.5
            14.7
            3.5Fair
                  Value (b)
            5.9
            14.5
            3.3





Expected
                MaturityCommodity
                Swaps
            2007
            2008
            2009Pay
                  fixed/receive variable (b)
            32.6
            64.1
            4.6Average
                  pay rate (a)
            8.7730
            8.7904
            10.0009Average
                  received rate (a)
            7.7880
            8.5623
            9.5130Fair
                  value (b)
            29.0
            62.4
            4.4





(a)Weighted
                average, in dollars(b)Millions
                of
                dollars




**ITEM
      4T.  CONTROLS AND
      PROCEDURES**





As
      of
      June 30, 2007, South Carolina Electric & Gas Company (SCE&G) conducted
      an evaluation under the supervision and with the participation of its
      management, including its Chief Executive Officer (CEO) and Chief Financial
      Officer (CFO), of (a) the effectiveness of the design and operation of its
      disclosure controls and procedures and (b) any change in its internal control
      over financial reporting. Based on this evaluation, the CEO and CFO concluded
      that, as of June 30, 2007, SCE&G’s disclosure controls and procedures
      were effective. There has been no change in SCE&G’s internal control over
      financial reporting during the quarter ended June 30, 2007 that has materially
      affected or is reasonably likely to materially affect
      SCE&G’s  internal control over financial reporting.




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**PART
      II. OTHER INFORMATION**







**ITEM
      2.UNREGISTERED SALES OF EQUITY SECURITIES AND
      USE OF PROCEEDS**





SCANA
      Corporation:







The
      following table provides information about purchases by or on behalf of SCANA
      Corporation (SCANA) or any affiliated purchaser (as defined in Rule 10b-18(a)(3)
      under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares
      or other units of any class of SCANA's equity securities that are registered
      pursuant to Section 12 of the Exchange Act:







Issuer
                Purchases of Equity Securities(d)Maximum
                number(c)
            (or
                approximateTotal
                number of
            dollar
                value) of(a)
            
            shares
                (or units)
            shares
                (or units)Total
                number of
            (b)
            purchased
                as part of
            that
                may yet beshares
                (or units)
            Average
                price paid
            publicly
                announced
            purchased
                under thePeriod
            purchased
            per
                share (or unit)
            plans
                or programs
            plan
                or programApril
                1-30
            307,251
            $44.17
            307,251May
                1-31
            116,055
            43.92
            116,055June
                1-30
            82,458
            41.33
            82,458Total
            505,764
            
            505,764
            *





*On
      May
      16, 2006 SCANA announced a program to convert from original issue to open market
      purchase of SCANA common stock for all applicable compensation and dividend
      reinvestment plans.  This program has no stated maximum number
      of  shares that may be purchased and no stated expiration
      date.








**ITEM
      4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
      HOLDERS (not applicable for South**


**Carolina
      Electric & Gas Company).**





The
      Annual Meeting of Shareholders of
      SCANA Corporation Common Stock (No Par Value) was held on April 26,
      2007.  The following matters were voted upon at the
      meeting.





1.          To
      elect three (3) Class II Directors for the terms specified in the Proxy
      Statement.





Nominee
            Number
                of
              Shares
                Voting
              For
            Number
                of Shares
              Voting
                to
              Withhold
                Authority
            Total
              Shares
              VotedW.
                Hayne Hipp
            97,883,829
            1,385,437
            99,269,266Harold
                C. Stowe
            97,913,048
            1,356,218
            99,269,266G.
                Smedes York
            97,918,853
            1,350,413
            99,269,266





2.          To
      approve the appointment of Deloitte & Touche LLP as independent auditors for
      SCANA Corporation.





Number
              of
              SharesFOR
            98,444,282AGAINST
            419,587ABSTAIN
            405,397TOTAL
            99,269,266




Table
          of Contents


**ITEM
      6.  EXHIBITS**





SCANA
      Corporation (SCANA) and South Carolina Electric & Gas Company
      (SCE&G):





Exhibits
      filed or furnished with this Quarterly Report on Form 10-Q are listed in the
      following Exhibit Index.





As
      permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining
      the
      rights of holders of long-term debt of less than 10 percent of the total
      consolidated assets of SCANA, for itself and its subsidiaries, and of SCE&G,
      for itself and its consolidated affiliates, have been omitted and SCANA and
      SCE&G agree to furnish a copy of such instruments to the Commission upon
      request.








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          of Contents


SIGNATURES





Pursuant
      to the requirements of the Securities Exchange Act of 1934, each of the
      registrants has duly caused this report to be signed on its behalf by the
      undersigned thereunto duly authorized. The signature of each registrant shall
      be
      deemed to relate only to matters having reference to such registrant and any
      subsidiaries thereof.







**SCANA
                CORPORATION****SOUTH
                CAROLINA ELECTRIC & GAS COMPANY**(Registrants)

















By:
            /s/James
                E. Swan, IVAugust
                3, 2007
            James
                E. Swan, IVController(Principal
                accounting officer)





























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          of Contents


EXHIBIT
      INDEX





Applicable
                to
              Form 10-Q ofExhibit
              No.
            SCANA
            SCE&G
            Description3.01
            X
            
            Restated
                Articles of Incorporation of SCANA Corporation as adopted on
                April 26, 1989 (Filed as Exhibit 3-A to Registration Statement
                No. 33-49145 and incorporated by reference herein)3.02
            X
            
            Articles
                of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to
                Registration Statement No. 33-62421 and incorporated by reference
                herein)3.03
            
            X
            Restated
                Articles of Incorporation of South Carolina Electric & Gas
                Company, as adopted on May 3, 2001 (Filed as Exhibit 3.01 to
                Registration Statement No. 333-65460 and incorporated by reference
                herein)3.04
            
            X
            Articles
                of Amendment effective as of the dates indicated below and filed
                as
                exhibits to the Registration Statements or Exchange Act reports set
                forth
                below and are incorporated by reference hereinMay 22,
                2001
            Exhibit 3.02
            to
                Registration No. 333-65460June 14,
                2001
            Exhibit 3.04
            to
                Registration No. 333-65460August 30,
                2001
            Exhibit 3.05
            to
                Registration No. 333-101449March 13,
                2002
            Exhibit 3.06
            to
                Registration No. 333-101449May 9,
                2002
            Exhibit 3.07
            to
                Registration No. 333-101449June 4,
                2002
            Exhibit 3.08
            to
                Registration No. 333-101449August 12,
                2002
            Exhibit 3.09
            to
                Registration No. 333-101449March 13,
                2003
            Exhibit 3.03
            to
                Registration No. 333-108760May 22,
                2003
            Exhibit 3.04
            to
                Registration No. 333-108760June 18,
                2003
            Exhibit 3.05
            to
                Registration No. 333-108760August 7,
                2003
            Exhibit 3.06
            to
                Registration No. 333-108760February
                26, 2004
            Exhibit
                3.05
            to
                Form 10-K for the year ended December 31, 2004May 18,
                2004
            Exhibit 3.05
            to
                Form 10-Q for the quarter ended June 30, 2004June 18,
                2004
            Exhibit 3.06
            to
                Form 10-Q for the quarter ended June 30, 2004August 12,
                2004
            Exhibit 3.05
            to
                Form 10-Q for the quarter ended Sept. 30,
                2004March
                9, 2005
            Exhibit
                3.11
            to
                Form 10-Q for the quarter ended Sept. 30,
                2005May
                16, 2005
            Exhibit
                3.12
            to
                Form 10-Q for the quarter ended Sept. 30,
                2005June
                15, 2005
            Exhibit
                3.13
            to
                Form 10-Q for the quarter ended Sept. 30,
                2005August
                16, 2005
            Exhibit
                3.14
            to
                Form 10-Q for the quarter ended Sept. 30,
                2005March
                14, 2006
            Exhibit
                3.01
            to
                Form 8-K dated March 17, 2006May
                11, 2006
            Exhibit
                3.01
            to
                Form 8-K filed May 15, 2006June
                28, 2006
            Exhibit
                3.01
            to
                Form 8-K filed June 29, 2006August
                16, 2006
            Exhibit
                3.01
            to
                Form 8-K filed August 17, 2006March
                13, 2007
            Exhibit
                3.01
            to
                Form 8-K filed March 15, 2007May
                22, 2007
            Exhibit
                3.01
            to
                Form 8-K filed May 23, 2007June
                22, 2007
            Exhibit
                3.01
            to
                Form 8-K filed June 26, 20073.05
            
            X
            Articles
                of Correction filed on June 1, 2001 correcting May 22, 2001
                Articles of Amendment (Filed as Exhibit 3.03 to Registration
                Statement No. 333-65460 and incorporated by reference
                herein)3.06
            
            X
            Articles
                of Correction filed on February 17, 2004 correcting Articles of
                Amendment for the dates indicated below and filed as exhibits to
                the 2003
                Form 10-K as set forth below and are incorporated by reference
                hereinMay 3,
                2001
            Exhibit 3.06May 22,
                2001
            Exhibit 3.07June 14,
                2001
            Exhibit 3.08August 30,
              2001
            Exhibit 3.09March 13,
              2002
            Exhibit 3.10May 9,
              2002
            Exhibit 3.11June 4,
              2002
            Exhibit 3.12August 12,
              2002
            Exhibit 3.13


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Applicable
                to
              Form 10-Q
                ofExhibit
              No.
            SCANA
            SCE&G
            DescriptionMarch 13,
                2003
            Exhibit 3.14May 22,
                2003
            Exhibit 3.15June 18,
                2003
            Exhibit 3.16August 7,
                2003
            Exhibit 3.173.07
            
            X
            Articles
                of Correction dated March 17, 2006, correcting March 14, 2006 Articles
                of
                Amendment (Filed as Exhibit 3.02 to Form  8-K dated March 17,
                2006 and incorporated by reference herein)3.08
            
            X
            Articles
                of Correction dated September 6, 2006, correcting August 16, 2006
                Articles
                of Amendment (Filed as Exhibit 3.01 to Form 8-K filed September 7,
                2006
                and incorporated by reference herein)3.09
            X
            
            By-Laws
                of SCANA as revised and amended on December 13, 2000 (Filed as
                Exhibit 3.01 to Registration Statement No. 333-68266 and
                incorporated by reference herein)3.10
            
            X
            By-Laws
                of SCE&G as revised and amended on February 22, 2001 (Filed as
                Exhibit 3.05 to Registration Statement No. 333-65460 and
                incorporated by reference herein)31.01
            X
            
            Certification
                of Principal Executive Officer Required by Rule 13a-14 (Filed
                herewith)31.02
            X
            
            Certification
                of Principal Financial Officer Required by Rule 13a-14 (Filed
                herewith)31.03
            
            X
            Certification
                of Principal Executive Officer Required by Rule 13a-14 (Filed
                herewith)31.04
            
            X
            Certification
                of Principal Financial Officer Required by Rule 13a-14 (Filed
                herewith)32.01
            X
            
            Certification
                of Principal Executive Officer Pursuant to 18 U.S.C.
                Section 1350 (Furnished herewith)32.02
            X
            
            Certification
                of Principal Financial Officer Pursuant to 18 U.S.C.
                Section 1350 (Furnished herewith)32.03
            
            X
            Certification
                of Principal Executive Officer Pursuant to 18 U.S.C.
                Section 1350 (Furnished herewith)32.04
            
            X
            Certification
                of Principal Financial Officer Pursuant to 18 U.S.C.
                Section 1350 (Furnished herewith)





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