Scana 8-K Investor Presentation August 2010 Bill Timmerman Chairman & CEO Jimmy Addison Sr. VP & CFO

Exhibit 99.1

Investor Presentation August 2010 Bill Timmerman Chairman & CEO Jimmy Addison Sr. VP & CFO

Safe Harbor Statement 2

Financial

Key Investment Highlights High quality, low risk utility Regionally focused, regulated electric & gas utilities (96% regulated EPS) Growing service territories Experienced, results-oriented management with ~30 average years utility experience 12+% insider / employee ownership Transparent, regulated growth plan Strategic, regulated growth plan focused on retail markets in the Southeast Capex supports system growth, environmental mandates and new generation Cost-effective new nuclear generation planned for 2016 and 2019 EPC agreement with risk sharing mechanism Supportive political and regulatory environment in all jurisdictions Strong financial profile Investment grade credit ratings Strong liquidity Balanced approach to financing growth Competitive total return prospects Increase EPS by an average annual growth rate of 4-6% over the next 3-5 years Maintain a dividend payout ratio of 55-60% 4

Electric & Natural Gas CGT Pipeline System Natural Gas Only EPS – 2009FY Total Assets – 12/31/09 Regulated Non-Regulated Business Overview 5 SCE&G 660,000 electric and 310,000 gas customers as of 6/30/10 Year over year customer growth as of June 2010: 0.9% electric and 1.1% gas 23 generating facilities totaling 5,638MW generating capacity Electric distribution system: 24,700 miles of lines 3,570 miles of electric right of way Top quartile safety record within SEE Gas distribution system: 15,900 miles of distribution mains 2 LNG plants with 1,880 MMCF of storage PSNC 468,000 customers as of 6/30/10 Year over year customer growth as of March 2010: 1.3% CGTC Nearly 1,500 miles of transmission pipeline Complementary non-regulated businesses Retail Gas Marketing (GA), Energy Marketing, Communications and ServiceCare 94% 6% 96% 4%

Earnings Goal: To Increase EPS by an average annual growth rate of 4-6% over the next 3-5 years Dividend Policy: To increase the annual cash dividend at a rate that reflects the earnings growth in the Company’s businesses, while maintaining a payout ratio of 55-60% Common dividends: Dividend History: Increased annual cash dividend 9 consecutive years and in 55 of the last 57 years 6-yr CAGR: 4.5% (1) Dividends are Important to Total Return Story 6 (1): Indicated annual rate Regional customer growth Additions to rate base Growth Environmental New Generation Supportive regulation Supportive legislation Long-term Earnings Drivers $1.46 $1.56 $1.68 $1.76 $1.84 $1.88 $1.90 $0.00 $0.50 $1.00 $1.50 $2.00 2004 2005 2006 2007 2008 2009 2010

Earnings per Share & Guidance Year to Date 2009 Year to Date 2010 $0.25 $1.00 $1.39 $0.15 ($0.01) $0.24 $0.19 $0.00 $1.45 $1.02 7 2010 Narrowed Guidance: $2.90 - $3.05

CAPEX 2010E-2012E 8 ($ in Millions) 2010E 2011E 2012E TOTAL SCE&G - Normal Generation $100 $83 $102 $285 Transmission & Distribution 190 199 236 625 Other 31 21 32 84 Gas 49 55 59 163 Common 25 18 10 53 Total SCE&G - Normal 395 376 439 1,210 PSNC Energy 59 67 63 189 Other 38 28 31 97 Total “Normal” 492 471 533 1,496 New Nuclear 468 586 853 1,907 Cash Requirements for Construction 960 1,057 1,386 3,403 Nuclear Fuel 77 6 85 168 Total Estimated Capital Expenditures $1,037 $1,063 $1,471 $3,571

Forward offering of equity completed the equity needs for 2010 and 2011 Financing Plan 2010E -2012E 9 Complete ($ in Millions) 2010E 2011E 2012E Debt Refinancings: SCANA - $300 $250 SCE&G - 150 - PSNC - 150 - New Issues: SCE&G - 250 600 PSNC 100 - - Total Debt $100 $850 $850 Equity 401(k)/DRP 90 95 100 Additional (estimated) 150 150 150 Total Equity $240 $245 $250

Note: $1.1 Billion Credit Facility Expires December 2011, plan to renew in 2010 Liquidity 10 Current Credit Facilities ($MM) $400 $250 $250 $200 $1,100 SCE&G SCFC PSNC SCANA Total `

Regulatory

SCE&G and PSNC rate cases typically filed every 2-3 years; annual fuel adjustment clauses Annual new nuclear capex cost recovery is formulaic under BLRA By law, all South Carolina rate cases are resolved within 6 months Approximately 60% of 2010 – 2012 capex is recovered through approved regulatory mechanisms rather than formal rate case proceedings All rate cases since 2005 have been resolved via settlement (1) Base rates enacted 7/10; rate base as of 9/30/09; actual ROE for 12 months ended 9/30/09 (2) New base rates enacted 11/09 Regulation & Rate Design 12 ($ in Millions) Rate ROE Rate Design ’10-’12 Base Allowed Actual Process Frequency Test Year Capex SCE&G Electric (1) $4,821 10.70% 6.82% Rate Case 2-3 yrs Historic $1,215 Gas (2) 442 10.25% 10.63% RSA Annual Historic 163 New Nuclear - 11.00% - Formulaic Annual Historic 1,907 Fuel/PP-Electric - - - Fuel Adj Annual Forward - Fuel -Gas - - - Fuel Adj Monthly Forward - PSNC Gas 700 10.60% 11.30% Rate Case 2-3 yrs Historic 189 Fuel - - - Fuel Adj Annual Historic - CGTC Transmission 159 12.70% ~12.50% Formulaic Annual Forward 29 Other 68 TOTAL $6,122 $3,571

SC Regulatory Structure Base Load Review Act – PSC Docket # 2008-196-E 13 Key Provisions: Up-front prudence Annual rate adjustments providing cash return (financing cost) on CWIP Projected test year for in-service costs Preapproved 11.0% ROE on nuclear expenditures Actions to Date: State Order affirming prudence and allowing construction and operations Initial rate increase for CWIP through June 2008, effective March 2009 First revised rate adjustment for CWIP through June 2009, effective November 2009 Revised Milestone Schedule approved January 2010 Abandonment Stipulation: “Where a plant is abandoned after a base load review order approving rate recovery has been issued, the capital costs and AFUDC related to the plant shall nonetheless be recoverable under this article provided that the utility shall bear the burden of proving by a preponderance of the evidence that the decision to abandon construction of the plant was prudent.”

Core Utility Operations BLRA Filings Filed Revenue Requested Revenue Granted % Req. Granted % Increase Effective BLRA Initial Filing 05/30/08 $7.8 $7.8 100% 0.4% APR ‘09 BLRA Annual RRA 05/29/09 $22.5 $22.5 100% 1.1% NOV ‘09 BLRA Annual RRA 05/28/10 $54.6 ** ** 2.7% NOV ‘10 2010 Regulatory Schedule New Nuclear Annual Matters Other Activities 2/16 – Q1 Status Report 2/28 - Integrated Resource Plan Filing 4/1 – DSM Hearing 5/17 – Q2 Status Report 3/25 – Electric Fuel Cost Review Retail Electric Base Case (See Slide 15) Aug – Q3 Status Report 5/28 - BLRA Revised Rate Application Nov – Q4 Status Report 6/15 - Gas RSA Filing Completed Regulatory Update 14 ($ in Millions) ** Pending

Customer Impact: 1.20% July 2010 July 2011 July 2012 EIZ Credit $48 MM 1.18% 1.18% WNA Credit $25 MM 1.20% Customer Impact 2.50% 3.70% 4.88% Base Rate Increase 4.88% 4.88% 4.88% July 2010 July 2011 July 2012 Revenue Increase $101.2 M $101.2 M $101.2 M Weather Credit to Customers ($25 M) Amortization of Q1 Weather Reserve $25 M EIZ Credit - Revenue Reduction ($24 M) ($24 M) Accelerated Amortization of State Tax Expense (EIZ Credits) ($24 M) ($24 M) Net Customer Credit Impact on I/S $101.2 M $101.2 M $101.2 M Financial Statement Impact (Annual Impact): Rate Case Conclusions 15

Nuclear Strategy

Reserve Margin: Target 12% - 18% Need for base load generation by 2016 The Need For New Generation 17 Current Capacity Planned Capacity 12.0% Target Floor 18.0% Target Ceiling Reserve Margin Requirements Peakers Added Nuclear Added 5,000 5,500 6,000 6,500 7,000 7,500 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Megawatts

Why Nuclear? Note: As of December 31, 2009 18 Favorable cost structure and capacity factors Advances goal of fuel diversity Financially sound instate partner Positive public support 2005 Energy Bill Incentives Current Generation Mix 2019 Generation Mix Non-emitting 23% Non-emitting 59% 2009 Cost Estimates vs. Avg Capacity Factors $76 $88 $97 $345 $682 Biomass 1% Hydro 4% Coal 51% Nuclear 18% Gas 26% $0 $175 $350 $525 $700 Nuclear Combined Cycle Coal Wind (Offshore) Solar (PV) 2009 Estimates ($/MWh) 0% 25% 50% 75% 100% Average Capacity Facotors Fixed Cost Variable Cost Avg. Capacity Factor Gas 7% Nuclear 55% Coal 34% Hydro 3% Biomass 1%

South Carolina is a Pro Nuclear State US REP. JOHN SPRATT (D-SC) – 4/1/08 “V.C. Summer Plant has proven its value, as a generator of electricity and as a good corporate citizen. I am glad to see its owners, SCE&G and Santee-Cooper, move one step closer to the construction of a new reactor. Nuclear power now supplies half our electricity in South Carolina, and its role is essential for our future if we are to meet the demand for electricity while diminishing carbon emissions.” US SENATOR LINDSEY GRAHAM (R-SC) –3/31/08 “I’m very pleased and excited to hear SCE&G and Santee Cooper have applied to construct and operate two new nuclear power plants in South Carolina. The additional use of nuclear power is one of the major steps we must take to become more energy independent as a nation. The benefits of nuclear power are clear: It is reliable, efficient, and safe. It helps lessen our dependence on foreign oil. It is an environmentally-friendly energy source which does not pollute our air or produce carbon emissions .” “I strongly support this application. Construction and operation of new nuclear power plants will provide South Carolina with abundant, affordable power for decades to come.” 19 SC ranked 3rd in the US in nuclear capacity 7 commercial reactors already in SC Greater than 50% nuclear capacity Barnwell low level waste facility available only to SC, CT and NJ Savannah River Site Westinghouse nuclear fuels plant in SC Naval Nuclear Power Training Command in Charleston, SC Innovative Base Load Review Act (BLRA)

Total Project Cost to Date BLRA – 2010 Revised Rate Filing 20

BLRA – March 2010 Quarterly Filing Projected Project Costs Forecast Item Projected @ 3/31/2010 (Five-Year Average Rates) As Forecasted Or Approved In Order 2010-12 Change Gross Construction $6,244,160 $6,875,315 ($631,155) Less: AFUDC $329,357 $315,739 $13,618 Total Project Cash Flow $5,914,803 $6,559,576 ($644,773) Less: Escalation $1,380,056 $2,024,829 ($644,773) Capital Cost, 2007 Dollars $4,534,747 $4,534,747 $0 Chart B: Reconciliation of Capital Cost ($000) Project Milestones % Total Milestones Completed 48 out of 146 33% Forecasted escalation costs will vary as authorized escalation indices are revised. 21

Note: As filed in BLRA May 2008 New Nuclear Capex Schedule & Impact to Rates 22 New nuclear capex recovery independent of SCE&G rate case activity Annual new nuclear capex cost recovery is formulaic BLRA provides small year over year rate increases, thus mitigating rate shock at Commercial Operation Date New Nuclear Capex and Rate Adjustments SCE&G Share (Millions of $ in Future Value) $0 $150 $300 $450 $600 $750 $900 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Capital Expenditures 0% 1% 2% 3% 4% 5% Rate Increase New Nuclear Plant Cost Transmission Plant Cost AFUDC Rate Increase

60 Year design life - modular construction concept Generation III – passive design State approvals granted Feb 2009 NRC COL expected late 2011 / early 2012 Total combined 2,234MW new nuclear generation; 1,229MW (55%) owned by SCE&G 1st 1,117MW AP1000 plant operational in 2016 2nd 1,117MW AP1000 plant operational in 2019 More than 50% of EPC contract fixed / fixed with escalation Nuclear Technology / Project Data 23

(1): Confidentiality agreement with Consortium prevents further disclosure Project Costs: $6.3 billion (escalated) >50% EPC Costs Fixed / Fixed with Escalators EPC Agreement with Westinghouse / Shaw Group 24 7 EPC Cost Categories 4 Fixed / Fixed with Escalation (> 50% of Total) (1) 3 Variable Based on Actual Cost Risk Profile for Each Category 2 Owners’ Cost Categories Variable Risk Profile Price Escalation linked to Indices in BLRA Contingencies Contractual SCANA

Partnerships – Shared Knowledge 25 Santee Cooper: Joint Ownership SCANA (55%) = 1,229 MW Santee Cooper (45%) = 1,005 MW Partnership Strengths: Current relationship – Partners in VC Summer Unit 1 State Political Support Investment Grade Credit Ratings China: Reciprocal agreement to share AP1000 knowledge SCE&G has access to Chinese nuclear construction site throughout build cycle China gets operational insight First Chinese arrive Sept. 2010 Benefits to SCE&G: China already ahead in construction by three years Ability to learn from their experiences

Federal Loan Guarantee Program 26 Current Status: Filed Part I & II of application in late 2008 May 2009 - Named 1 of 4 projects considered for additional due diligence Submitted preliminary credit assessment in 3rd quarter 2009 Negotiation of final terms not likely until late 2010 Next Step: www.lgprogram.energy.gov Current Rule Establishing Loan Guarantee Program (10 CFR part 609) Key Concerns: Allocation of $18.5 billion available funds / potential additional authorization Determine up-front credit subsidy cost and other fee structures Collateral package & covenants / commercial terms

 Overview of Key Provisions of SCE&G’s BLRA Reporting 27

28 Manufacturing Schedules – May 2010 2009 2010 2011 2012 2013 2014 U2 & U3-Reactor Coolant Loop Piping Unit 2-Reactor Vessel Unit 2-Steam Generators Unit 2-Containment Vessel Unit 2-Integrated Head Package Unit 2-RCP VFDs Unit 2-Squib Valves Unit 2-CRDMs Unit 3-Containment Vessel Unit 3-CRDMs Unit 3-Squib Valves Unit 3-RCP VFDs Unit 3-Integrated Head Package (Complete April 2015) Unit 3-Reactor Vessel Unit 3-Steam Generators- (Complete Feb 2015) Unit 2-Pressurizer Unit 3-Pressurizer U2- Core Makeup Tanks U 3- Core Makeup Tanks Unit 2-Accumulators Unit 3- Accumulators Unit 2-RCPs Unit 3-RCPs (Complete June 2015) RCP VFD Testing Unit 2-Turbine Generator Unit 3-Turbine Generator (Complete April 2015)

RCPs VFDs RV Internals CRDMs Modules PZR, PRHR, CMT, ACC, Main loop pipe RV, SGs Main TG Condenser MSRs FWHs CV SG tubing IHP 29

cold leg round bar hot leg ingot 30

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After Machining

34 System Projected Carbon Emissions (Millions of Tons) 1995 levels 2005 levels 17 % Below 2005 levels

Photos

November 2008 –Aerial View VCS Unit 1 New Nuclear Deployment Office

VC Summer Site - January 2010 Warehouse Area Construction Offices Equipment Laydown Area VCS Units 2&3 37 Mayo Creek Bridge

Batch Plant Module Assembly Building Unit 2 Power Block Excavation VCS New Construction Site Shaw Training Facility

Module Assembly Building Concrete Placement

Module Assembly Building

Module Assembly Building & Unit 2 Excavation

42 Circulating Water Pipe Staged

Unit 3 Circulating Water System Piping Placement

Unit 3 Circulating Water System Piping Placement

First Concrete Batch Plant

Training Facility Addition

China Update Sanmen AP1000 Site Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC

Sanmen Containment Vessel Lower Bowl China Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC 48

Sanmen CA-04 Module China Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC 49

50 Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC Sanmen Containment vessel ring transport

Sanmen Lifting First CV Ring into Place on Lower Bowl Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC 51

Sanmen Lifting 2nd CV Ring into Place Images are copyrighted and are courtesy of Westinghouse Electric Company, LLC 52

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