UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 16, 2009

DUKE ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Delaware		001-32853		20-2777218
(State or Other Jurisdiction of Incorporation)		(Commission File Number)		(IRS Employer Identification No.)

526 South Church Street, Charlotte, North Carolina 28202

(Address of Principal Executive Offices, including Zip code)

(704) 594-6200

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240. 13e-4(c))

Item 8.01. Other Events.

On February 16, 2010, Duke Energy Corporation will host an investor and analyst meeting to discuss fourth quarter 2009 and year-end 2009 results, including a discussion of its financial and business outlook for 2010 and beyond. Additionally, the presentation will include a discussion of the Company’s 2010 per share earnings outlook of $1.25 to $1.30, based upon adjusted diluted earnings. A copy of this presentation is attached hereto as Exhibit 99.1.

Item 9.01. Financial Statements and Exhibits.

	(d)	Exhibits.

	99.1	Duke Energy Investor and Analyst Meeting presentation

	99.2	Duke Energy Corporation Adjusted to Reported Earnings Reconciliation

	99.3	Duke Energy Corporation Non-GAAP Reconciliations

SIGNATURE

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	DUKE ENERGY CORPORATION


Date: February 16, 2010	By:	/s/Steven K. Young
	Name:	Steven K. Young
	Title:	Senior Vice President and Controller

EXHIBIT INDEX

Exhibit		Description

99.1		Duke Energy Investor and Analyst Meeting presentation

99.2		Duke Energy Corporation Adjusted to Reported Earnings Reconciliation

99.3		Duke Energy Corporation Non-GAAP Reconciliations

Exhibit 99.1

February 16, 2010 DUKE ENERGY INVESTOR AND ANALYST MEETING

Stephen De May Senior Vice President, Investor Relations and Treasurer WELCOME AND SAFE HARBOR STATEMENT

SAFE HARBOR STATEMENT Some of the statements in this document concerning future company performance will be forward-looking within the meanings of the securities laws. Actual results may materially differ from those discussed in these forward-looking statements, and you should refer to the additional information contained in Duke Energy’s 2008 Form 10-K filed with the SEC and our other SEC filings concerning factors that could cause those results to be different than contemplated in today's discussion. REG G DISCLOSURE In addition, today's discussion includes certain non-GAAP financial measures as defined under SEC Regulation G. A reconciliation of those measures to the most directly comparable GAAP measures is available on our Investor Relations website at www.duke-energy.com/investors/. SUPPLEMENTAL INFORMATION Supplemental information related to today’s presentation can be accessed via our Investor Relations website at www.duke-energy.com/investors/. This supplemental information includes presentation appendix materials. 3

TODAY’S AGENDA 4 Welcome & Safe Harbor Stephen De May Opening Remarks Jim Rogers U.S. Franchised Electric & Gas Jim Turner Regulated Generation Dhiaa Jamil Commercial Businesses Keith Trent Financial Overview Lynn Good Q&A and Wrap-Up Jim Rogers

DUKE ENERGY OVERVIEW 5 27,000 MW of regulated generation Electric transmission & distribution Natural gas distribution U.S. Franchised Electric & Gas Commercial Power International * Forecasted 2010 adjusted segment Earnings Before Interest and Taxes (EBIT) contribution (based upon midpoint of 2010 adjusted diluted EPS range). Percent of forecasted adjusted total segment EBIT does not include results for the operations labeled as Other. 7,600 MW of unregulated generation Wind and renewable business 4,000 MW of primarily Latin American generation assets Investment in National Methanol

DE Ohio (including DE Kentucky) DE Indiana DE Carolinas OVERVIEW OF CORPORATE STRUCTURE 6 (1) Primarily coal assets dedicated to serve Duke Energy Ohio’s native load customers in the Electric Security Plan.

Lynn Good, Group Executive and Chief Financial Officer Responsibilities: Controller’s office Treasury & investor relations Tax Risk management & insurance Mergers and acquisitions Financial planning & forecasting Corporate strategy Keith Trent, Group Executive and President — Commercial Businesses Responsibilities: Midwest non-regulated generation Renewables business Duke Energy International Commercial strategy and policy Jim Turner, Group Executive; President and Chief Operating Officer — U.S. Franchised Electric and Gas Responsibilities: Power delivery Gas distribution Customer service Fuel and portfolio optimization Wholesale business New generation projects Environmental health and safety Legislative and regulatory strategy and policy Economic development Dhiaa Jamil,Group Executive, Chief Generation Officer and Chief Nuclear Officer Responsibilities: Regulated generation operations including fossil, hydro and nuclear Nuclear plant development Supply chain Implementation of environmental controls TODAY’S PRESENTERS 7

Jim Rogers Chairman, President and Chief Executive Officer OPENING REMARKS

2009 FINANCIAL HIGHLIGHTS 10 Measure Target Result Adjusted Diluted EPS $1.20 Exceeded O&M Reductions $100 million increased to $150 million Exceeded CapEx Reductions $200 – $300 million Achieved (at low end of range) 4Q09 4Q08 2009 2008 Reported Diluted EPS $ 0.26 $ 0.26 $0.83 $ 1.07 Adjustments 0.02 0.06 0.40 0.20 Discontinued Operations - - (0.01) (0.01) Extraordinary Items - (0.05) - (0.05) Adjusted Diluted EPS $ 0.28 $ 0.27 $1.22 $1.21

2010 EARNINGS OUTLOOK 11 $1.25 – $1.30 2010 Adjusted Diluted EPS Outlook Range

OUR ACCOMPLISHMENTS FOR 2009 Doing what we said we would do Continued to modernize our regulated infrastructure and obtain recovery of those costs NC, SC, OH and KY rate case orders Progress on Cliffside and Edwardsport major construction projects Smart Grid approval in Ohio Continued to manage through the recession Managed our costs and had exceptional operational performance Continued our commercial success and protected our margin in Ohio Continued to maintain liquidity and protect our balance sheet strength Issued ~$500 million of equity through our DRIP and internal plans Issued $3.75 billion of fixed-rate debt at 5.2% during 2009 Maintained strong investment-grade credit ratings 12 Attractive Dividend Yield and Total Shareholder Return

STRATEGIC FOCUS – 2010 AND BEYOND Modernization, Portfolio Diversification and Financial Strength 13 Build new generation Maintain operational excellence Build a smart grid Expand energy efficiency Shape federal and state policies Achieve constructive regulatory outcomes Regulated Operations Effectively compete in Ohio; accelerate DERS activity Grow renewables; underpin with long-term contracts and utilize and shape federal/state policies Reinvest off-shore cash in International Commercial Businesses Allocate and rotate capital efficiently to earn competitive returns Maintain a strong balance sheet Grow earnings and dividends Financial Strength

14 Generation and grid modernization strategies Outlook for future ratemaking activity Preparations for an uncertain future, especially for new environmental regulations Strategic positioning of our commercial businesses Long-term growth and financial objectives GOALS FOR TODAY Drill down into the business

Jim Turner Group Executive; President and Chief Operating Officer, U.S. Franchised Electric and Gas U.S. FRANCHISED ELECTRIC AND GAS

FRANCHISED ELECTRIC AND GAS VALUE PROPOSITION 17

FLEET MODERNIZATION Carolinas Modernization (through 2020) Indiana Modernization (through 2020) 18 Capacity (MW) Capacity (MW) Wabash River Legacy Edwardsport Remaining Unscrubbed Units to be Evaluated for Retirement/ Controls Edwardsport Renewables Cliffside Unit 6 Buck and Dan River Gas Plants Renewables Cliffside Commitments Other Planned Retirements Fleet modernization enables the company to meet long-term load growth and to offset plant retirements

STATUS OF MODERNIZATION PROJECTS 19 2 1 Project costs include direct capital and AFUDC 2 IURC approved project costs of $2.35 billion in 2009; cost estimate to be updated during 2010 3 Cost estimate is under review 4 Level of estimated expenditures could be impacted by outcome in Indiana 4 3 Modernization projects progressing; Edwardsport project facing cost pressure

CONSTRUCTIVE REGULATORY OUTCOMES 20 Regulatory Research Associates State Regulatory Evaluations Favorable rate case outcomes will increase base rates by nearly $460 million upon full implementation CWIP recovery enabled/updated for Cliffside and Edwardsport projects Save-a-watt cost recovery mechanism enabled in the Carolinas Smart Grid deployment and cost recovery mechanisms initiated in Ohio Approval in North Carolina of Central Co-op wholesale deal will result in 1 GW of load by 2019 Approval of wind and solar projects will enable innovative renewable energy initiatives Key Regulatory Accomplishments – 2009 1Evaluations reflect the regulatory climate and are assigned from an investor perspective Duke Energy’s regulated businesses operate in constructive regulatory environments

PROJECTED RATE BASE GROWTH Projected Rate Base –Franchised Electric and Gas ($ in billions) $28.9 $26.7 2.8 $23.3 2.6 $20.9 2.3 7.1 2.1 7.0 6.5 5.6 18.2 16.3 12.5 13.8 Projected Rate Base = Prior Period Rate Base Add: Capital Expenditures Less: Depreciation & Amortization Less: Deferred Income Taxes Note: Generic formula used for presentation purposes only 2009 2010 2011 2012 Carolinas Indiana Ohio Kentucky Projected rate base growth helps drive USFE&G’s growth 21 Investor and Analyst Meeting, February 16, 2010

FOCUS ON REGULATORY RETURNS Projected Earned vs. Allowed Return on Equity (2010) ROE% 12% 10.7%(1) 10.5% 10.63%(2) 10.375%(3) Current Allowed ROE 9% 9.5 - 10.0% 8.5 - 9.0% 9.0% - 9.5% 6% 6.5 - 7.0% Projected Earned ROE Range 3% 0% Carolinas Indiana Ohio T&D Kentucky Key Levers to Address Regulatory Lag Frequent rate cases Legislative initiatives Capital and cost control (1) Rates established based upon 10.7% ROE; however, utility has the ability to earn up to 11.0% ROE in South Carolina. (2) 10.63% is an implied rate of return (i.e. no explicit ROE provided for in the order approving rates) and applies to Ohio T&D only. Ohio generation does not have specified ROEs. (3) The most recent electric case was settled without specifying a return. The most recent gas case was approved with a return of 10.375%. Investor and Analyst Meeting, February 16, 2010 22

FREQUENT RATE CASE ACTIVITY TO RECOVER COSTS 23 Gas Electric Electric Generation, T&D, Gas T&D Indicates rate case has concluded and new rates have been implemented Indicates year of projected revenue changes resulting from anticipated future rate actions Under Consideration or

REGULATORY AND LEGISLATIVE FOCUS (2010–2011) North Carolina and South Carolina Expect to file general rate cases in 2011; rates effective 2012 Advance legislative initiatives to address regulatory lag CWIP outside of a rate case for new nuclear Indiana Review need for filing general rate case in 2010 or 2011 Address Edwardsport cost pressures; gain clarity on direction of CCS Advance Smart Grid and energy efficiency plans Ohio Deploy strategy to meet alternative energy requirements Seek to improve certainty of recovery of new generation investments Advance Commercial Business regulatory/legislative strategy Federal Advocate for reasonable environmental regulations Advocate for extension of favorable dividend tax treatment 24

OPERATIONAL EXCELLENCE ENABLES CONSTRUCTIVE OUTCOMES 1SAIFI measures outrage frequency, so lower scores are favorable ¢/kWh % highly satisfied outage frequency metric 25 Duke Energy’s regulated businesses offer attractive customer value propositions

SHARP FOCUS ON COST CONTROL 26 Significant O&M cost reductions achieved during 2009 Efforts ongoing to deliver sustainable O&M reductions in 2010 and beyond Operational excellence and system reliability will continue as core priorities $ - Billion 1O&M costs are net of recoverables and deferrals Focus on making strong cost control results in 2009 sustainable in 2010 and beyond

Energy Efficiency Wholesale Origination Economic Development Save-a-watt model places investments in energy efficiency on more level footing with investments in power plants Save-a-watt approved in North Carolina, South Carolina, Indiana and Ohio; withdrew Kentucky filing – to be addressed in next rate case Looking at opportunities to expand the boundaries of our business beyond the meter and to move away from a kWh-through-the-meter business model Our competitive rates and reliable service create an attractive value proposition for potential wholesale customers Serving wholesale load benefits all customer classesas we spread costs across a larger customer base Highlights include Central Co-op deal, resulting in 1 GW of load by 2019 Site Selection magazine has named Duke Energy a "Top 10 Best" utility economic development program for the past 11 years Duke Energy’s economic development efforts have produced many wins in recent years, including notable data center projects for Google and Apple Economic development activities in 2009 result in approximately 100 MWs of load system-wide GROWTH AND DIVERSIFICATION 27 Revenue growth expanding beyond existing retail meters

DELIVERING SUPERIOR VALUE 28 Establish a strong earnings platform through the modernization of our fleet and grid and the deployment of innovative products and services that expand the boundaries of our regulated business Achieve sustainable cost reductions while maintaining operational excellence Ensure competitive returns and balance sheet strength through frequent rate case activity and pursue additional tools to minimize regulatory lag Maintain regulatory and legislative traction to mitigate the impacts of future environmental regulations Key Objective Create superior value for shareholders and customers by providing affordable, reliable and clean energy

U.S. FRANCHISED ELECTRIC AND GAS At-a-glance 30 5 states: North Carolina, South Carolina, Indiana, Ohio and Kentucky 50,000 square miles of service area Approximately 27,000 MW of regulated generating capacity 4 million retail electric customers 500,000 retail gas customers

U.S. FRANCHISED ELECTRIC AND GAS Diversity in geography, customer mix, and fuel mix 33%Residential 33%Commercial 22%Industrial (excl. Textiles) 2%Textiles 10%Wholesale/Other 58%Carolinas 42%Midwest 59%Coal 39%Nuclear 2% Hydro 0%Natural Gas / Oil 31 1 Based on 2009 GWH Sales

CAROLINAS’ RATE CASES Shaping constructive outcomes in difficult economic times North Carolina Order $315 million increase in base rates (65% of request) Riders reduce impact to customers in first 2 years Rates effective 1/1/2010 Allowed ROE of 10.7% and equity of 52.5% Duke Energy Carolinas agrees to forego a general rate case filing in 2010 Earliest general rate case filing will be in 2011 with a 2010 test year with rates effective no sooner than 1/1/2012 (USD in Millions) 2010 2011 2012 Base Rates $315 $315 $315 Deferral of Cliffsicle CWIP Cash Recovery (no earnings impact) (89) Estimated Carrying Charges on Coal Inventory 12 2 Return of Fuel Over-Collection(no earnings impact) (50) Return of Insurance Dividends (no earnings impact) (40) (40) Cumulative Net Increase to Customers ($) $148 $277 $315 Cumulative Net Increase to Customers (%) 3.8% 7.0% 8.0%(1). South Carolina Order $74 million increase in base rates (58% of request) Riders reduce impact to customers Rates effective 2/1/2010 Allowed ROE of 11%, with rates based upon 10.7% and equity of 53% Order includes compensation for save-a-watt energy efficiency programs Duke Energy Carolinas agrees to forego a general rate case filing in 2010 Earliest general rate case filing will be in 2011 with a 2010 test year with rates effective no sooner than 1/1/2012 (USD in Millions) 2010(3) 2011 2012 Base Rates $74 $74 $74 Return DSM Over-collection (no earnings impact) (44) (44) (44) Estimated Carrying Charges on Coal Inventory (estimated amounts) 3 1 Pension Cost Rider (estimated amounts) (2) 4 4 4 Return of Insurance Dividends (no earnings impact) (13) (13) Cumulative Net Increase to Customers ($) $24 $22 $34 Cumulative Net Increase to Customers (%) 1.7% 1.5% 2.41%(1) 1) Does not include any potential rate increases from general rate case proceedings that may take place in 2012. 2) Pension costs will vary from year to year based on various factors including market performance, fund contributions and actuarial assumptions. The Pension Cost Rider amount in 2010 is estimated to be $4 million. Subsequent years could be different. 3) Annualized amounts. As rates are effective 2/1/2010, 2010 impact will be approximately 11/12th of these amounts. Note: amounts above exclude any amounts recovered under Duke Energy Carolina’s energy efficiency plan (save-a-watt program)

RATE BASE AND REGULATORY MECHANISMS

Effective Use of Riders Reduces Volatility in Regulated Earnings Ohio Kentucky North South Carolina Carolina Indiana Electric Gas Electric Gas Current Rate Base $13.7B(6) $5.3B $1B $700M $600M (1) $200M (2) Current Allowed ROE 10.7% 11.0%(3) 10.50% 10.63% per settlement N/A per settlement N/A per settlement 10.375% Current Allowed Equity 52.5% 53% 44.44%(4) N/A per settlement (5) 55.76% 51.00% 50.8% Effective Date of Most Recent Rates 01/01/2010 02/01/2010 5/24/2004 07/08/2009 for Distribution ESP approved effective 01/01/2009 07/01/2008 01/01/2007 01/01/2010 Fuel Clause Updated Annually Annually Quarterly Quarterly Monthly Monthly Monthly Note: Table indicates current approved rate base, ROE’s and allowed equity Footnotes: (1) Kentucky allows recovery on total capitalization instead of rate base. (2) Reflects only the investment subject to KPSC jurisdiction. (3) Rates based upon 10.7% ROE (4) Indiana’s capital structure includes accumulated deferred income taxes (ADIT). (5) Settlement reflects a 58% common equity amount per the “actual adjusted capital structure” but does not specify 58%. (6) Includes $1B related to Cliffside CWIP in rate base. As part of the settlement in the NC rate case, recovery of Cliffside financing costs will begin in NC effective 1/1/2011.

STATE REGULATORY JURISDICTIONS Commission Overviews North Carolina South Carolina Indiana Ohio Kentucky Number 7 commissioners 7 commissioners 5 commissioners 5 commissioners 3 commissioners Term 8 year terms 4 year terms 4 year terms 5 year terms 4 year terms Appointed/ Appointed by Elected by the Appointed by Appointed by Appointed by Elected Governor legislature Governor Governor Governor Chairman Ed Finley Lib Fleming David Hardy Alan Schriber David Armstrong Term Expires June 30, 2011 June 30, 2010 April 2010 April 10, 2014 June 30, 2011 Other Bobby Owens Butch Howard Larry Landis Rhonda Fergus* James Gardner Commissioners Lorinzo Joyner William Culpepper O'Neal Hamilton Randy Mitchell Jim Atterholt David Ziegner Valerie Lemmie Paul Centolella Charles Borders Bryan Beatty Swain Whitfield Jeffrey Golc Cheryl Roberto Susan Rabon David Wright ToNola Brown-Bland One vacant seat * - will be replaced by Steven Lesser effective April 11, 2010

Dhiaa M. Jamil Group Executive, Chief Generation Officer and Chief Nuclear Officer REGULATED GENERATION Belews Creek – “Most Efficient Coal Plant in America” (2008)

REGULATED GENERATION VALUE PROPOSITION 37 Maximize operational performance of the regulated generation fleet, resulting in lower costs to customers Position regulated generation fleet for compliance with pending environmental regulations Maintain the option of new nuclear generation while managing appropriate regulatory frameworks

MAXIMIZING DIVERSITY OF REGULATED GENERATION Installed Capacity MW Coal Nuclear Gas/Oil Hydro NC/SC 19,204 40% 27% 16% 17% IN/KY 7,773 70% 0% 29% 1% Total 26,977 49% 19% 20% 12% Actual 2009 Generation Coal Nuclear Gas/Oil Hydro NC/SC 44% 54% 0% 2% IN/KY 98% 0% 1% 1% Total 59% 38% 0% 2% Diversity of fuel and geography reduces reliance on one particular economy, area and fuel, thus reducing price volatility for customers and risk for investors

FLEET OPERATIONAL EXCELLENCE – RELIABILITY 39 *The 2010E number indicates 2010 targets Record continuous unit operation Wabash River Unit 4 – 264 days Gibson Unit 5 – 223 days Commercial availability drivers Improved reliability of CT fleet Equipment reliability Cost control to improve marketability 2009 capacity factor second best in fleet history McGuire record capacity factor = 98.67% Oconee record capacity factor = 93.97% Capacity factor drivers Focus on outage planning/execution Continued focus on equipment reliability

FLEET OPERATIONAL EXCELLENCE – OPERATING COSTS 40 *The 2010E number indicates 2010 targets Cost control program successes O&M costs Capital costs Capital maintenance Production cost drivers Heat rate consistently “best in industry” Effective cost control program Low operating costs (lowest of peers in 2008) Operating cost drivers Lowest forced loss rate of fleets in 2009 Superior reliability Continued focus on outage management Effective cost control program Event-free performance (1) Fossil production cost 2009 industry data not yet available

DUKE ENERGY’S AGING GENERATION FLEET 41 Fleet modernization will result in the retirement of all coal plants put into service in the 1940s and earlier, and more than 30% of the plants put into service in the 1950s (MW)

REDUCING EMISSIONS INTENSITY 42 Approximately 75% of our current coal fleet has scrubbers and/or SCRs installed After completion of fleet modernization in 2018, approximately 90% will have either scrubbers and/or SCRs installed Fleetwide, Duke Energy has invested, and is recovering in rates, approximately $5 billion to install emissions control devices

WELL-POSITIONED FOR PENDING ENVIRONMENTAL REGULATIONS Pending Regulations Coal Regulation Coal Combustion Byproducts (CCB) Coal Ash – designation forthcoming by EPA, final regulation expected Q1 2011 Air Pollutant Regulation by EPA Clean Air Transport Rule (CATR) – final rule expected in mid-2011 Maximum Achievable Control Technology (MACT) – final rule expected in late-2011 National Ambient Air Quality Standards (NAAQS) – tighter for ozone, SO2 and PM Carbon Possible legislation and/or regulation by EPA Potential Impacts Fleet Modernization Additional air emissions control equipment installation Additional or accelerated unit retirements beyond current plans Additional Investments Magnitude under review Investment in larger plants first – spend expected after 2012 43

Cherokee County, SC – Lee Nuclear Two Westinghouse AP 1000 reactors 2,234 megawatts – two 1,117 megawatt units Filed COL with NRC in 2007 – under review Estimated commercial operation date of 2021 Piketon, OH Formed development alliance Evaluating potential sites, including DOE’s Portsmouth Site Requesting DOE funding for initial phase – environmental study for generic Early Site Permit MAINTAINING NEW NUCLEAR OPTIONS 44 Piketon, OH Cherokee County, SC

SOUTHEAST NUCLEAR DEVELOPMENT Key Considerations and Milestones 45 Federal License Approval Submitted license application in 2007; addressing requests for additional information Supportive State Regulatory Frameworks Pre-approval of construction costs and schedule Cash return on recovery of construction financing costs (CWIP) outside general rate case Regional Partnerships Allows sharing of construction, project management and operation risks Provides opportunity to add capacity in smaller increments over longer time periods Decision to Develop COL Application 2018 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Decision to Submit COL Application COL Approval From NRC Unit 1 Commercial Operation Date COL Application Preparation NRC Review and Hearing Plant Construction and Start-up 2019 2020 2021

46 DUKE ENERGY’S GENERATION STRATEGY Generation Environmental Nuclear Duke’s regulated generation fleet has diversity in geography and fuel sources Operationally, Duke’s regulated generation fleet continues to perform well ~75% of the coal fleet already has environmental controls and plans are in place to install additional controls Duke’s modernization plans position the company well for environmental compliance today and in the future In anticipation of a low-carbon future, we continue to keep the new nuclear option viable Having the right regulatory framework is critical Preference to develop regional partnerships

Keith Trent Group Executive and President, Commercial Businesses COMMERCIAL BUSINESSES

COMMERCIAL BUSINESSES VALUE PROPOSITION Diversified Sources of Earnings Growth and Cash Fuel Type Natural Gas Hydro Wind Coal / Oil Brazil 2,112 MW Guatemala 283 MW Ecuador 160 MW Peru 678 MW Wind – 735 MW Argentina 523 MW El Salvador 296 MW Midwest Generation Ohio generation (~4,000 MW) Midwest gas-fired generation (~3,600 MW) DEI Latin American assets National Methanol Other Renewables Wind Biomass Solar Commercial Transmission A tale of three businesses Midwest Generation - mature business with strong historical cash flows and earnings Renewables – investing in highly-contracted projects with attractive risk-adjusted returns and growth opportunities DEI – Self-funding with strong cash generation and earnings diversity / highly contracted 49

MIDWEST GENERATION Asset Profile 50 Midwest primarily coal-fired generation (~4,000 MW) Primarily low-cost base load coal plants Serves native-load customers in Ohio (via ESP) and wholesale markets All plants have SCR and FGD except 862 MW at Beckjord Midwest gas-fired generation (~3,600 MW) Capacity sold into PJM Capacity auctions Generation increased ~200 percent over 2008 ESP – Electric Security Plan FGD – Flue Gas Desulfurization SCR – Selective Catalytic Reductions Gwh Duke’s Midwest portfolio set record levels of generation in 2009, despite economic downturn and lower demand

MIDWEST GENERATION NAVIGATING OHIO’S COMPETITIVE ENVIRONMENT 51 CIN Hub Cal 10 ATC Power Prices A competitive market in Ohio since deregulation in 2000 Dramatic drop in demand and power prices occurred in early 2009 Current market price is below ESP price (which was established and approved in 2008) Switching resulted in lower retail sales and increased wholesale volumes, but at a lower margin Approximately 40 percent of DE Ohio’s customer load has switched away from the ESP1 Switching principally focused on commercial and industrial customers Customer switching accelerated in the 2nd half of 2009 Net switching of approximately 15% (net of load acquired by Duke Energy Retail Sales or DERS) Drop in commodity prices in 2009 results in competitive pressure in Ohio Over 30% reduction ESP development period 1As of December 31, 2009 DERS DE Ohio Customer Acquisitions Net Switching $30 $35 $40 $45 $50 $55 $60 $65 Jan - 08 Mar - 08 May - 08 Jul - 08 Sep - 08 Nov - 08 Jan - 09 Mar - 09 May - 09 Jul - 09 Sep - 09 Nov - 09 $/MWhr 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% Customer Switching % of Load Switched

MIDWEST GENERATION Our Competitive Response 52 Duke Energy Retail Sales responds to competitive pressures – minimizing margin erosion DERS Strategy Attract customers within the DE Ohio service territory (“defensive”) Attract customers outside the DE Ohio service territory (“offensive”) DERS has acquired approximately 60 percent of DE Ohio’s switched customer load* Net switching of ~15% results in net impact of approximately $0.02 EPS in 2009 DERS sales are hedged DE Ohio successfully acquired load through FirstEnergy auction *As of December 31, 2009 DERS other OH DERS DEO Territory FE Auction Switched ESP Load Note - Includes all customer classes; excludes additional wholesale volumes MWh (Monthly) 2009 Monthly Ohio Retail Load Switching Trend

2010 earnings challenges Increased customer switching in Ohio Customer switching in 2010 expected to average approximately 45%; an incremental 5% over December 2009 levels Estimated incremental EPS impact of $0.04 to $0.07 in 2010 vs. 2009 Fewer opportunities for emission allowance and coal sales as compared to 2009 Our focused response Drive down operating costs and maintenance capital expenditures Maximize and protect margin through DERS “defensive” and “offensive” efforts MIDWEST GENERATION What to Expect in 2010 53 Challenges in 2010 lead to continued focus on lowering costs and optimizing margins

MIDWEST GENERATION Looking Beyond 2011 54 Entering another ESP is a likely option post-2011 ESP price will be market-based Will also include additional ESP features embedded in SB 221 Under any framework, we have multiple options for our generation to maximize margin Dedicate to DE Ohio load in ESP Match generation to unaffiliated retail load (e.g. aggregated load) Target discrete customers/customer classes Sell into wholesale market DERS will be both strategic and opportunistic PJM capacity payments are expected to rise in future auctions Maintaining options to maximize margin in 2012 and beyond

Public policy drives growth prospects Natural extension of our business Energy infrastructure provider Proven construction management Operational excellence Attractive financial performance ITC and MACRS return much of initial capital in first year – approximately 35-40% for a typical wind project In 2009, bonus depreciation accelerated this to 45-50% Annual cash-on-cash returns are very attractive – 20-30% per annum over first 5 years of project Favorable risk-adjusted IRRs Risk mitigated by: Long-term PPA’s with credit-worthy counterparties Availability of project financing RENEWABLES Growth Opportunities 55 Driving growth in renewables while managing risk North Allegheny Kit Carson Top of the World Solar construction projects Biomass development pipeline Blue Wing

Proven execution in the wind business since 2007 Over $1 billion invested to date 2009 wind projects will generate approximately $300 million in cash from operations and tax benefits, principally ITC and bonus depreciation Principally long-term contracts with strong investment-grade counterparties Projects are coming in early and under budget Better than industry average availability 250 MW/year of wind growth targeted Replicating wind business model with other renewables Solar: Launched with 16 MWdc Blue Wing solar project Biomass: Launched with ADAGE JV RENEWABLES Proven Track Record of Attractive Growth in Wind 56 Leveraging successful wind business execution to different types of renewables

Clean, self-funding electric generation business principally focused on Brazil and Peru Principally hydro generation Annual free cash flow ~ $200 – 300 million Risk mitigated by: Highly contracted position in Brazil – average tenor over 5 years Regulated capacity price for reserve margin units in Peru Local currency debt in Brazil hedges changes in FX exchange rates DUKE ENERGY INTERNATIONAL Focused on Clean and Contracted Energy 57 High levels of contracting and capacity payments reduces risk profile

DUKE ENERGY INTERNATIONAL Sustained Earnings Growth 58 Sustainable earnings growth – operating in stable/growing economies DEI has produced long term EBIT growth Mature regulatory regimes in Brazil and Peru Brazil and Peru are stable/growing economies with strong electricity demand growth Latin America’s stable growth mitigates National Methanol’s (NMC) commodity exposure ($ in millions)

KEY TAKE-AWAYS 59 Commercial businesses - diverse earnings and growth opportunities, strong cash flows and solid returns Midwest Generation Managing through the current economic environment Maintaining options to maximize margin beyond 2012 Renewables Growth opportunities driven by public policy Demonstrated execution in the wind business – leveraged into other types of renewable energy sources International Provides geographic and earnings diversity Optimized levels of contracting and capacity payments reduce risk profile

NON-REGULATED MIDWEST GENERATION 61 PJM MISO 152 MW Gas 3,801 MW Coal/Oil Midwest Primarily Coal (ESP Dedicated) 7,553 MW Total Fleet 3,600 MW Gas Midwest Gas-Fired Dicks Creek (MISO)152 MW Type: 4 Simple Cycle Units Fuel: Natural Gas, #3NG/Oil Ownership: 100% Location: Middletown, OH In Service: 1965-1969 Miami Fort (MISO)700 MW Type: 2 Coal Units, 4 CT Units Fuel: Coal, Oil Ownership: Units 7&8 64%; 100% Location: North Bend, OH In Service: 1949-1978 Beckjord(MISO)1,074 MW Type: 6 Coal Units, 4 CT Units Fuel: Coal, Oil Ownership: Unit 6 37.5%; 100% Location: New Richmond, OH In Service: 1952-1972 Zimmer (MISO) 605 MW Type: 1 Coal Unit Fuel: Coal Ownership: 46.5% Location: Moscow, OH In Service: 1991 Conesville(MISO)312 MW Type: 1 Coal Unit Fuel: Coal Ownership: 40% Operator: AEP Location: Coshocton, OH In Service: 1973 Killen (MISO) 198 MW Type:1 Coal Unit Fuel: Coal Ownership: 33% Operator: DP&L Location: Wrightsville, OH In Service: 1982 Stuart (MISO) 912 MW Type: 4 Coal Units Fuel: Coal Ownership: 39% Operator: DP&L Location: Aberdeen, OH In Service: 1970-1974 Midwest Primarily Coal Hanging Rock (PJM) 1,240 MW Type: 2 Combined Cycle Units Fuel: Natural Gas Ownership: 100% Location: Ironton, OH In Service: 2003 Lee (PJM)640 MW Type: 8 Simple Cycle units Fuel: Natural Gas Ownership: 100% Location: Dixon, IL In Service: 2001 Fayette (PJM) 620 MW Type: 1 Combined Cycle Unit Fuel: Natural Gas Ownership: 100% Location: Masontown, PA In Service: 2003 Washington (PJM) 620 MW Type: 1 Combined Cycle Unit Fuel: Natural Gas Ownership: 100% Location: Beverly, OH In Service: 2002 Vermillion (MISO) 480 MW Type: 8 Simple Cycle units Fuel: Natural Gas Ownership: 75% Location: Cayuga, IN In Service: 2000 Midwest Gas Fired RTO MISO PJM 3,120 MW 4,433 MW

Wind In Service Wind In Service (Cont.) Sweetwater 1-5 283 MW Type: 175 GE 1.5 MW, 135 Mitsubishi 1 MW, & 81 Siemens 2.3 MW Ownership: 1-3 50%; 4-5 47% PPA: 1- 20 yr TXU Portfolio Management Co, LP 2- 12 yr Austin Energy 3- Austin Energy (12 yr 35 MW) ,CPS San Antonio (20 yr 100 MW) 4- 20 yr CPS San Antonio 5- Merchant Location: Nolan County, TX In Service: 2003-2007 NON-REGULATED RENEWABLES PORTFOLIO 62 Happy Jack 29 MW Type: 14 Suzlon 2.1 MW turbines Ownership: 100% PPA: Cheyenne Light Fuel & Power Location: Larame County, WY In Service: September 2008 Ocotillo59 MW Type: 28 Suzlon 2.1 MW turbines Ownership: Units 100% PPA: 80% 3 yr Barclays price hedge; 20% Merchant Location: Howard Co, TX In Service: November 2008 Notrees153 MW Type: 1A - 55 Vestas 1.65 MW; 1B - 40 GE 1.5 MW; 1C – 1 Vestas 1.86 MW turbines Ownership: 100% PPA: 52% 4 yr Texas Retail Energy; 48% Merchant Location: Ector and Winkler County, TX In Service: April 2009 Campbell Hill99 MW Type: 66 GE 1.5 MW turbines Ownership: 100% PPA: 20 yr Pacificorp Location: Natrona and Converse County, WY In Service: December 2009 Silver Sage42 MW Type: 20 Suzlon 2.1 MW turbines Ownership: 100% PPA: 20 yr Platte River Auth,Cheyenne Light Fuel& Power Location: Laramie County, WY In Service: October 2009 Kit Carson 51 MW Type: 34 GE 1.5 MW turbines Ownership: 100% PPA: 20 yr Tri-State Generation & Transmission Assoc. Location: Kit Carson County, CO Projected In Service: Q4 2010 Top of the World200 MW Type: 66 GE 1.5 MW, 44 Siemens 2.3 MW Ownership: 100% PPA: 20 yr Pacificorp Location: Converse County, WY Projected In Service: Q4 2010 Wind Under Construction Blue Wing Solar Under Construction North Allegheny70 MW Type: 35 Gamesa 2.0 MW turbines Ownership: 100% PPA: 23.5 yr First Energy Solutions Location: Blair and Cambria County, PA In Service: September 2009 Blue Wing1 16 MW dc Type: 215,000 First Solar thin film PV panels Ownership: 100% PPA: 30 yr CPS Energy Location: San Antonio, TX Projected In Service: Q4 2010 Non-Regulated Renewables Portfolio (MW) Wind In Service 735 MW Wind Under Construction 251 MW Solar Under Construction 16 MW Development Pipeline ~5,000MW 1 – Acquisition closing expected Q1 2010.

DUKE ENERGY INTERNATIONAL HONDURAS COSTA RICA PANAMA NICARAGUA MEXICO BELIZE COLOMBIA VENEZUELA BRAZIL GUATEMALA PARAGUAY ARGENTINA CHILE URUGUAY GUYANA SURINAME FRENCH GUYANA ECUADOR Lima Sao Paulo Buenos Aires PERU Guatemala BOLIVIA Houston San Salvador Guatemala 283 MW El Salvador 296 MW Ecuador 160 MW Peru – Egenor 501 MW Peru – Aguaytia 177 MW Argentina 523 MW Brazil 2,112 MW 63

INTERNATIONAL – NATIONAL METHANOL (NMC) AND FX 64 Partnership Structure: SABIC (50%), Celanese (25%) and Duke Energy (25%) Duke Energy interest acquired thru acquisition of PanEnergy (Texas Eastern an original investor) Joint Venture agreement signed in 1981, license to expire in 2012 (negotiations underway regarding extension) Historically has made up approximately 20-30% of DEI’s adjusted segment EBIT (expected to continue in 2010) National Methanol (NMC) Foreign Exchange (FX) Duke Energy has exposure to fluctuations in the value of multiple currencies The largest exposure is to the Brazilian Real Every 10% change in Brazilian Real/US$ exchange rates (for a full year) has an approximate $0.01 EPS impact

Lynn Good Group Executive and Chief Financial Officer FINANCIAL OVERVIEW

2009 FINANCIAL HIGHLIGHTS Adjusted Diluted EPS 2009 Actual vs. Plan ($ millions) 2009 Plan 2009 Actual USFE&G Adjusted Segment EBIT $2,400 $2,321 Commercial Power Adjusted Segment EBIT 470 500 International Adjusted Segment EBIT 370 409 Other Adjusted Net Expense (250) (200) Capital Expenditure 4,750 4,557 Exceeded employee incentive target of $1.20 adjusted diluted EPS Offset retail sales volumes reductions through cost controls and strong operational performance Exceeded $150 million O&M cost reduction target Reduced capital expenditures by ~$200 million Mitigated competitive pressures in Ohio Maintained strength of the balance sheet Company delivers on its commitments in a challenging environment

USFE&G 2009 VOLUME TRENDS Stabilizing Stabilizing Volume trends are on a weather-normalized, period-to-period basis 68

KEY ASSUMPTIONS FOR 2010 69

2010 OUTLOOK – ADJUSTED SEGMENT EBIT 2010 Adjusted Segment EBIT Expectations ($ millions) 2009 2010E* U.S. Franchised Electric & Gas $2,321 $2,630 Commercial Power 500 315 International 409 485 Total Adjusted Segment EBIT $3,230 $3,430 Other (Net Expense) (200) (255) Total Adjusted Segment EBIT and Other $3,030 $3,175 * Adjusted segment EBIT expectations based upon midpoint of 2010 adjusted diluted EPS range Rate base growth in regulated businesses offsets decline in Midwest generation (in the Commercial Power segment), resulting in adjusted EBIT growth expectations for 2010

LONG-TERM GROWTH EXPECTATIONS OF 4-6%* $1.25 - $1.30* adjusted EPS range for 2010 Represents 4-5% increase from 2009 Economic downturn and the extent and timing of economic recovery have impacted our growth expectations Load growth Commodity prices Competition in Ohio Earnings from Crescent Actions to achieve growth going forward Manage capital spending and mitigate regulatory lag Control our costs and maintain operational excellence Grow commercial businesses with appropriate risk-adjusted returns Lower Commodity Prices Lower Load Growth Source – CIN Hub Cal 10 ATC Power Prices * Based upon adjusted diluted earnings per share 71 $30 $35 $40 $45 $50 $55 $60 $65 Jan - 08 Mar - 08 May - 08 Jul - 08 Sep - 08 Nov - 08 Jan - 09 Mar - 09 May - 09 Jul - 09 Sep - 09 Nov - 09 $/MWhr 122,000 124,000 126,000 128,000 130,000 132,000 134,000 136,000 2007 2008 2009 2010 2011 2012 2013 2014 GWh

2010 SUMMARY CASH FLOWS Illustrative based upon midpoint of 2010 adjusted diluted EPS range Proceeds from asset sales, working capital changes, and non-cash AFUDC equity Continued access to the debt capital markets to fund the 2010 business plan Equity issued through internal plans to maintain the strength of the balance sheet. International USFE&G Commercial Power Other 2010E Segment CapEx 72

CAPITAL EXPENDITURE PROFILE 2010E 2011E 2012E Cumulative Committed Capital Edwardsport IGCC $ 910 $ 280 $ 80 $ 1,270 CC / CT Additions – Carolinas 420 380 170 970 Nuclear Fuel 240 390 310 940 Cliffside 440 240 80 760 Smart Grid (1) 130 310 290 730 Renewables 430 - - 430 Environmental 130 60 120 310 International 120 - - 120 Lee Nuclear 60 30 20 110 Other 50 40 10 100 Total Committed Capital 2,930 1,730 1,080 5,740 Ongoing Capital Maintenance and Other 1,850 2,040 1,940 5,830 Customer Additions 220 330 380 930 Total Ongoing Capital 2,070 2,370 2,320 6,760 Total Committed and Ongoing Capital $ 5,000 $ 4,100 $ 3,400 $ 12,500 Total Discretionary Capital (2) 200 500 – 1,000 500 – 1,500 $ 1,200 – 2,700 Total Capital Expenditures $ 5,200 $ 4,600 – 5,100 $ 3,900 – 4,900 $ 13,700 – 15,200 ($ in millions) All Smart Grid expenditures included in Committed Capital based upon $1 billion program; however, regulatory approval has only been received in Ohio. Discretionary capital primarily includes Commercial renewables and transmission, International, and USFE&G renewables 73

CONTINUED DIVIDEND GROWTH Dividend expected to grow at a slower rate than growth in adjusted-diluted EPS Dividend payout ratio to trend downward (based on adjusted-diluted EPS) 2% increase assumed for 2010 $1.3 billion of expected dividend payments in 2010 Indicative Annual Dividend Rate as of Year-end Spectra Energy Spin-Off Projected 74

EXPECTED 2010 DEBT ISSUANCES DE Carolinas DE Ohio DE Indiana DE Kentucky DEGS DEI Duke Energy Total Estimated Debt Issuances (1) (2) $600 $ - $510 $ - $315 $315 $535 $2,275 Scheduled Debt Maturities (505) (5) (5) (5) (30) (225) - (775) Potential DebtRefinancing - - (125) - - (225) (275) (625) (1) Includes projected changes in short-term debt and commercial paper (2) Excludes potential tax-exempt refundings/refinancings Certain treasury strategies could increase actual 2010 financing levels (e.g., prefunding 2011 requirements, etc.) DEGS financings reflect non-recourse project financings for renewables (wind) Refinancing activity includes the repayment of amounts drawn under the Master Credit Facility at Duke Energy and DE Indiana Duke’s financing plan is achievable and is consistent with our credit rating objectives

BALANCE SHEET STRENGTH Committed to current credit ratings Ratings have stable or positive outlooks Plan maintains strong credit metrics in line with current ratings Strong liquidity and access to capital support our business plan Available liquidity of approximately $2.8 billion at year-end 2009 Unused credit facility capacity of $1.9 billion Planned repayments of credit facility draws in 2010 will increase available capacity by $400 million Cash and short-term investments of $0.9 billion (excludes $600 million of cash in foreign jurisdictions) In 2009, issued $3.75 billion of fixed-rate debt at 5.2% and weighted average maturity of more than 14 years 76

SUMMARY — FINANCIAL OBJECTIVES Grow Earnings and Dividends Allocate Capital Efficiently and Earn Competitive Returns Maintain a Strong Balance Sheet Adjusted diluted EPS CAGR of 4-6% off a 2009 base is achievable Deploy capital consistent with our business mix (maintain 75% regulated vs. 25% non-regulated mix) Management is committed to maintaining the current credit ratings Growth in 2010 adjusted diluted EPS – outlook range of $1.25 to $1.30 Mitigate regulatory lag in our regulated jurisdictions Planned equity issuances of $400 million in 2010 from DRIP and internal plans Continued growth in dividend but at a rate slower than the growth in adjusted diluted EPS Achieve appropriated risk-adjusted returns in our non-regulated businesses Plan supports targe credit metrics Maintaining strong liquidity Duke Energy’s financial strategy supports our overall objective to maintain balance sheet strength and adequate liquidity, grow earnings and dividends and earn risk-adjusted returns

2009 HIGHLIGHTS – U.S. FRANCHISED ELECTRIC & GAS Reported & Adjusted Segment EBIT ($ millions) 4Q09 4Q08 2009 2008 Reported Segment EBIT $548 $ 532 $2,321 $ 2,398 Adjustments - - - - Adjusted Segment EBIT $548 $ 532 $2,321 $2,398 FOR THE QUARTER Adjusted segment EBIT increased primarily due to $24 million as a result of lower depreciation rates in the Carolinas $10 million increase in equity AFUDC as a result of the ongoing construction program $7 million increase due to wholesale sales Partially offset by $14 million due to lower volumes (principally industrial customers) $22 million due to prior year rate riders in the Carolinas FOR THE YEAR Adjusted segment EBIT decreased primarily due to $117 million due to lower volumes (principally industrial customers) $63 million due to unfavorable weather Partially offset by $69 million as a result of lower depreciation rates in the Carolinas $36 million decrease in O&M costs principally due to lower outage costs 79

Investor and Analyst Meeting, February 16, 2010 0 500 1,000 1,500 2007 2008 2009 Textiles 0 500 1,000 1,500 2007 2008 2009 Primary Metals 0 250 500 750 1,000 1,250 2007 2008 2009 Chemicals 0 3,000 6,000 9,000 12,000 2007 2008 2009 Total Industrial (Billed GwH) (Billed GwH) (Billed GwH) (Billed GwH) Q1 Q2 Q3 Q4 Note: The above includes non-weather normalized quarterly billed Gwh sales for Duke Energy’s top three industrial classes as well as total industrial (includes both Carolinas and Midwest) from 1Q07 to 4Q09 INDUSTRIAL VOLUME QUARTERLY TRENDS 80

81 2009 FINANCIAL HIGHLIGHTS – COMMERCIAL POWER Reported & Adjusted Segment EBIT ($ millions) 4Q09 4Q08 2009 2008 Reported Segment EBIT $68 ($ 9) $27 $ 264 Adjustments 32 110 473 157 Adjusted Segment EBIT $100 $ 101 $500 $ 421 FOR THE QUARTER Adjusted segment EBIT was relatively flat primarily due to

$37 million decrease in retail volumes resulting from economic downturn and customer switching

Partially offset by

$16 million of improved results from the Midwest gas assets

$16 million increase in non-native margins due to gains on coal sales FOR THE YEAR

Adjusted segment EBIT increased primarily due to

$90 million from increased margins due to Ohio ESP rates

$58 million of improved results from the Midwest gas assets

Partially offset by

$66 million decrease in retail volumes resulting from economic downturn and customer switching

Adjustments due to mark-to-market on economic hedges and 3Q09 impairments

82 2009 FINANCIAL HIGHLIGHTS – DEI Reported & Adjusted Segment EBIT ($ millions) 4Q09 4Q08 2009 2008 Reported Segment EBIT $104 $ 104 $365 $ 411 Adjustments 18 - 44 - Adjusted Segment EBIT $122 $ 104 $409 $ 411 FOR THE QUARTER Adjusted segment EBIT increased primarily due to $15 million due to favorable foreign currency exchange rates $13 million increased contribution from National Methanol due to higher MTBE margins FOR THE YEAR Adjusted segment EBIT decreased primarily due to $45 million decreased contribution from National Methanol due to lower methanol and MTBE prices $25 million due to unfavorable foreign currency exchange rates Partially offset by $39 million in Peru due to lower thermal generation and purchased power costs $26 million in Central America as a result of higher dispatch due to favorable hydrology 2009 adjustments due to an impairment of our non-core equity investment in Greece and an adverse ruling on prior years’ transmission fees in Brazil

83 Reported & Adjusted Net Expense ($ millions) 4Q09 4Q08 2009 2008 Reported Net Expense $58 $ 108 $251 $ 568 Adjustments (2) (10) (51) (258) Adjusted Net Expense $ 56 $ 98 $ 200 $ 310 FOR THE QUARTER Adjusted net expense decreased due to $18 million of improved investment performance $11 million of favorable governance costs $7 million of lower captive insurance losses 2009 FINANCIAL HIGHLIGHTS – OTHER FOR THE YEAR Adjusted net expense decreased due to $45 million of improved investment performance $18 million of favorable governance costs $16 million of prior year equity losses at Crescent $12 million of lower captive insurance losses 2009 Adjustments due to Crescent guarantees and costs to achieve related to the Cinergy merger

OTHER FINANCIAL ITEMS - 2009 Interest expense, net of debt AFUDC and capitalized interest, for 2009 was $751 million Debt AFUDC and capitalized interest for 2009 was $102 million Equity AFUDC for 2009 was $153 million Interest income and other was $120 million during 2009 Effective tax rate of approximately 41% for 2009, reported Reported effective tax rate for 2009 includes the effect of a non-deductible goodwill impairment recognized in the third quarter of 2009 Effective tax rate of approximately 34% for 2009, adjusted 84

Investor and Analyst Meeting, February 16, 2010 CAPITAL EXPENDITURES – USFE&G ($ in millions) 2010E 2011E 2012E Cumulative US Franchised Electric & Gas System Growth 2,250 $ 1,630 $ 1,120 $ 5,000 $ Maintenance and Other 1,570 1,720 1,670 4,960 Nuclear Fuel 240 390 310 940 Environmental 90 10 50 150 Total US Franchised Electric & Gas 4,150 $ 3,750 $ 3,150 $ 11,050 $ System Growth Edwardsport IGCC 910 $ 280 $ 80 $ 1,270 $ CC / CT Additions - Carolinas 420 380 170 970 Customer Additions 220 330 380 930 Cliffside 440 240 80 760 Smart Grid 130 310 290 730 Renewables 60 50 90 200 Lee Nuclear 60 30 20 110 Other Regulated Investments 10 10 10 30 Total USFE&G System Growth 2,250 $ 1,630 $ 1,120 $ 5,000 $ 85

Investor and Analyst Meeting, February 16, 2010 CAPEX – SYSTEM GROWTH AND MAINTENANCE (BY UTILITY) ($ in millions) 2010E 2011E 2012E Cumulative System Growth Carolinas 1,120 $ 940 $ 630 $ 2,690 $ Indiana 960 450 280 1,690 Ohio 150 220 200 570 Kentucky 20 20 10 50 Total System Growth 2,250 $ 1,630 $ 1,120 $ 5,000 $ Maintenance and Other Carolinas 1,130 $ 1,160 $ 1,060 $ 3,350 $ Indiana 220 310 350 880 Ohio 180 200 200 580 Kentucky 40 50 60 150 Total Maintenance and Other 1,570 $ 1,720 $ 1,670 $ 4,960 $ 86

SIMPLIFIED FINANCING STRUCTURE (DEC. 31, 2009) Commercial Paper and LT Financings Project / International Financings Money Pool and LT Financings Duke Energy Corporation Revolver Sublimit: $1.097 B LTD Outstanding: $2.6 B Total Consolidated LTD: $17.0 B Duke Energy Carolinas Revolver Sublimit: $840 M LTD Outstanding: $7.7 B DE International LTD Outstanding: $0.9 B Duke Energy Ohio Revolver Sublimit: $650 M LTD Outstanding: $2.2 B Duke Energy Kentucky Revolver Sublimit: $100 M LTD Outstanding: $0.3 B Duke Energy Indiana Revolver Sublimit: $450 M LTD Outstanding: $3.1 B Cinergy Corp. Other Non-Reg LTD Outstanding: $0.2 B 87

Investor and Analyst Meeting, February 16, 2010 LIQUIDITY SUMMARY ($ in millions) Duke Energy DE Carolinas DE Ohio DE Indiana DE Kentucky Total Facility Size (1) 1,097 $ 840 $ 650 $ 450 $ 100 $ 3,137 $ Less: Notes Payable and Commercial Paper (2) - (300) - (150) - (450) Drawdown (274) - - (123) - (397) Outstanding Letters of Credit (LOCs) (12) (109) - - - (121) Tax-Exempt Bonds (25) (95) (84) (81) - (285) Available Capacity 786 336 566 96 100 1,884 Cash & Short-Term Investments (3) 929 Total Available Liquidity 2,813 $ (1) Master Credit Facility supports tax-exempt bonds, LOCs and the Duke Energy commercial paper program of $2.2 billion (2) Reflects permanent layer of commercial paper, classified as long-term debt (3) Excludes certain cash and short-term investments in foreign jurisdictions of approximately $600 million As of December 31, 2009 88

Investor and Analyst Meeting, February 16, 2010 Date Issuer Security Amount January Duke Energy 6.30% Unsecured due 2/2014 750 $ March DE Ohio 5.45% FMB due 4/2019 450 March DE Indiana 6.45% FMB due 4/2039 450 August Duke Energy 3.95% Unsecured due 9/2014 500 August Duke Energy 5.05% Unsecured due 9/2019 500 September DE Kentucky 4.65% Unsecured due 10/2019 100 November DE Carolinas 5.30% FMB due 2/2040 750 December DE Ohio 2.10% FMB due 6/2013 (1) 250 3,750 $ Date Issuer Security Amount January DE Indiana Variable Rate Demand Bonds (2) 271 $ June DE Indiana 6.00% NC10 Term Bonds due 8/2039 (3) 55 September DE Carolinas 3.60% Term Bonds due 2/2017 (3) 77 October DE Indiana 4.95% NC10 Term Bonds due 10/2040 (3) 50 453 $ 2009 FINANCINGS COMPLETED Weighted Average Rate of 5.2% ($ in millions) 2009 Fixed Rate Financings (1) Swapped to floating rate (2) Refunded auction rate securities (3) Refinanced/refunded variable rate demand bonds, eliminating credit enhancement 2009 Tax-Exempt Refinancings/Refundings 89

LONG-TERM DEBT MATURITIES (2010 – 2012) (1) ($ in millions) (1) Excludes outstanding borrowings under the master credit facility and potential debt refinancings/refundings. 90 $775 $600 $1,850

CREDIT RATINGS SUMMARY Moody’s S&P Duke Energy Stable Positive Issuer Rating / Corporate Credit Rating Baa2 A- Senior Unsecured Baa2 BBB+ Commercial Paper P-2 A-2 DE Carolinas Stable Positive Senior Secured A1 A Senior Unsecured A3 A- DE Ohio Positive Positive Senior Secured A2 A Senior Unsecured Baa1 A- DE Indiana Stable Positive Senior Secured A2 A Senior Unsecured Baa1 A- DE Kentucky Stable Positive Senior Unsecured Baa1 A- Investor and Analyst Meeting, February 16, 2010

Jim Rogers Chairman, President and Chief Executive Officer Q&A AND WRAP-UP

Exhibit 99.2

DUKE ENERGY CORPORATION

ADJUSTED TO REPORTED EARNINGS RECONCILIATION

December 2009 Quarter-to-Date

(Dollars in millions, except per-share amounts)

				Special Items (Note 1)
				Costs to						Economic
				Achieve,						Hedges
	Adjusted			Cinergy						(Mark-to-			Discontinued			Total			Reported
	Earnings			Merger			Impairments			Market)*			Operations			Adjustments			Earnings
*SEGMENT EARNINGS BEFORE INTEREST AND TAXES*
*FROM CONTINUING OPERATIONS*

U.S. Franchised Electric and Gas	$	548		$	—		$	—		$	—		$	—		$	—		$	548

Commercial Power	100			—			—			(32		)(B)	—			(32		)	68

International Energy	122			—			(18		)(D)	—			—			(18		)	104

Total reportable segment EBIT	770			—			(18		)	(32		)	—			(50		)	720

Other	(56		)	(2		)(A)	—			—			—			(2		)	(58		)

Total reportable segment and Other EBIT	$	714		$	(2	)	$	(18	)	$	(32	)	$	—		$	(52	)	$	662

Interest Expense	(191		)	—			—			—			—			—			(191		)
Interest Income and Other	23			—			—			—			—			—			23
Income Taxes from Continuing Operations	(177		)	1			6			12			—			19			(158		)
Discontinued Operations, net of taxes	—			—			—			—			12		(C)	12			12
Net Income Attributable to Non-controlling Interests	2			—			—			—			—			—			2

*Net Income (Loss) Attributable to Duke Energy Corporation*	$	367		$	(1	)	$	(12	)	$	(20	)	$	12		$	(21	)	$	346
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC*	$	0.28		$	—		$	—		$	(0.02	)	$	—		$	(0.02	)	$	0.26
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED*	$	0.28		$	—		$	—		$	(0.02	)	$	—		$	(0.02	)	$	0.26

Note 1 - Amounts for special items are presented net of any related noncontrolling interest.

(A) - $4 million credit recorded in Operation, maintenance and other and $6 million expense recorded in Depreciation and amortization (all Operating Expenses) on the Consolidated Statements of Operations.

(B) - $7 million loss recorded within Non-regulated electric, natural gas, and other (Operating Revenues) and $25 million loss recorded within Fuel used in electric generation and purchased power-non-regulated (Operating Expenses) on the Consolidated Statements of Operations.

(C) - Recorded in Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

(D) - Recorded in Losses on sales and impairments of unconsolidated affiliates within Other income and expenses on the Consolidated Statements of Operations.

Weighted Average Shares (reported and adjusted) - in millions

Basic		1,306

Diluted		1,307

* Represents the mark-to-market impact of derivative contracts in the non-native portfolio, which is recognized in earnings immediately as such derivative contracts do not qualify for hedge or regulatory accounting, used in Duke Energy’s hedging of a portion of the economic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commodities (e.g. coal, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations of the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement better matches the financial impacts of the hedge contract with the portion of the economic value of the underlying hedged asset. Management believes that the presentation of adjusted diluted EPS Attributable to Duke Energy Corporation provides useful information to investors, as it allows them to more accurately compare the company’s performance across periods.

DUKE ENERGY CORPORATION

ADJUSTED TO REPORTED EARNINGS RECONCILIATION

December 2009 Year-to-Date

(Dollars in millions, except per-share amounts)


				Special Items (Note 1)
				Costs to
				Achieve,			Crescent Related			International			Goodwill and			Economic
	Adjusted			Cinergy			Guarantees and			Transmission			Other			Hedges (Mark-			Discontinued			Total			Reported
	Earnings			Merger			Tax Adjustments			Adjustment			Impairments			to-Market)*			Operations			Adjustments			Earnings
*SEGMENT EARNINGS BEFORE INTEREST AND TAXES FROM CONTINUING OPERATIONS*

U.S. Franchised Electric and Gas	$	2,321		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	2,321

Commercial Power	500			—			—			—			(413		)(D)	(60		)(B)	—			(473		)	27

International Energy	409			—			—			(26		)(E)	(18		)(D)	—			—			(44		)	365

Total reportable segment EBIT	3,230			—			—			(26		)	(431		)	(60		)	—			(517		)	2,713

Other	(200		)	(25		)(A)	(26		)(F)	—			—			—			—			(51		)	(251		)

Total reportable segment and Other EBIT	$	3,030		$	(25	)	$	(26	)	$	(26	)	$	(431	)	$	(60	)	$	—		$	(568	)	$	2,462

Interest Expense	(745		)	—			—			(6		)	—			—			—			(6		)	(751		)
Interest Income and Other	120			—			—			—			—			—			—			—			120
Income Taxes from Continuing Operations	(818		)	10			(3		)	10			21			22			—			60			(758		)
Discontinued Operations, net of taxes	—			—			—			—			—			—			12		(C)	12			12
Net Income Attributable to Noncontrolling Interests	10			—			—			—			—			—			—			—			10

*Net Income (Loss) Attributable to Duke Energy Corporation*	$	1,577		$	(15	)	$	(29	)	$	(22	)	$	(410	)	$	(38	)	$	12		$	(502	)	$	1,075
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC*	$	1.22		$	(0.01	)	$	(0.02	)	$	(0.02	)	$	(0.32	)	$	(0.03	)	$	0.01		$	(0.39	)	$	0.83
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED*	$	1.22		$	(0.01	)	$	(0.02	)	$	(0.02	)	$	(0.32	)	$	(0.03	)	$	0.01		$	(0.39	)	$	0.83

Note 1 - Amounts for special items are presented net of any related noncontrolling interest.

(A) - $5 million recorded in Operation, maintenance and other and $20 million recorded in Depreciation and amortization (all Operating Expenses) on the Consolidated Statements of Operations

(B) - $2 million loss recorded within Non-regulated electric, natural gas, and other (Operating Revenues) and $58 million loss recorded within Fuel used in electric generation and purchased power-non-regulated (Operating Expenses) on the Consolidated Statements of Operations.

(C) - Recorded in Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

(D)- $413 million recorded in Goodwill and other impairment charges within Operating Expenses and $18 million recorded in Losses on sales and impairments of unconsolidated affiliates within Other income and expenses on the Consolidated Statements of Operations.

(E) - $30 million recorded in Operation, maintenance and other, $2 million recorded as a reduction to fuel used in electric generation and purchased power - non-regulated, and $2 million as a reduction to Net income (loss) attributable to noncontrolling interests on the Consolidated Statements of Operations.

(F)- Recorded in Other income and expenses, net on the Consolidated Statements of Operations.

Weighted Average Shares (reported and adjusted) - in millions

Basic		1,293

Diluted		1,294

DUKE ENERGY CORPORATION

ADJUSTED TO REPORTED EARNINGS RECONCILIATION

December 2008 Quarter-to-Date

(Dollars in millions, except per-share amounts)

				Special Items (Note 1)
				Costs to			Economic			Discontinued
				Achieve,			Hedges			Operations/
	Adjusted			Cinergy			(Mark-to-			Extraordinary			Total			Reported
	Earnings			Merger			Market)*			Items			Adjustments			Earnings
*SEGMENT EARNINGS BEFORE INTEREST AND TAXES* *FROM CONTINUING OPERATIONS*
U.S. Franchised Electric and Gas	$	532		$	—		$	—		$	—		$	—		$	532
Commercial Power	101			—			(110		)(B)	—			(110		)	(9		)
International Energy	104			—			—			—			—			104
Total reportable segment EBIT	737			—			(110		)	—			(110		)	627
Other	(98		)	(10		)(A)	—			—			(10		)	(108		)
Total reportable segment EBIT and other EBIT	$	639		$	(10	)	$	(110	)	$	—		$	(120	)	$	519
Interest Expense	(189		)	—			—			—			—			(189		)
Interest Income and Other	26			—			—			—			—			26
Income Taxes from Continuing Operations	(139		)	4			40			—			44			(95		)
Discontinued Operations, net of taxes	—			—			—			2		(C)	2			2
Extraordinary Items, net of taxes	—			—			—			67		(D)	67			67
Net Income Attributable to Noncontrolling Interests	(1		)	—			—			—			—			(1		)
*Net Income (Loss) Attributable to Duke Energy Corporation*	$	338		$	(6	)	$	(70	)	$	69		$	(7	)	$	331
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC*	$	0.27		$	—		$	(0.06	)	$	0.05		$	(0.01	)	$	0.26
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED*	$	0.27		$	—		$	(0.06	)	$	0.05		$	(0.01	)	$	0.26

Note 1 - Amounts for special items are presented net of any related noncontrolling interest.

(A) - $5 million recorded in Operation, maintenance and other and $5 million recorded in Depreciation and amortization (all Operating Expenses) on the Consolidated Statements of Operations.

(B) - $34 million loss recorded within Non-regulated electric, natural gas, and other (Operating Revenues) and $76 million loss recorded within Fuel used in electric generation and purchased power (Operating Expenses) on the Consolidated Statements of Operations.

(C) - Recorded in Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

(D) - Recorded in Extraordinary Items, net of tax on the Consolidated Statements of Operations.

Weighted Average Shares (reported and adjusted) - in millions

Basic		1,267
Diluted		1,268

* Represents the mark-to-market impact of derivative contracts in the non-native portfolio, which is recognized in earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting, used in Duke Energy’s hedging of a portion of the economic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commodities (e.g. coal, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations of the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement better matches the financial impacts of the hedge contract with the portion of the economic value of the underlying hedged asset. Management believes that the presentation of adjusted diluted EPS Attributable to Duke Energy Corporation provides useful information to investors, as it allows them to more accurately compare the company’s performance across periods.

DUKE ENERGY CORPORATION

ADJUSTED TO REPORTED EARNINGS RECONCILIATION

December 2008 Year-to-Date

(Dollars in millions, except per-share amounts)

				Special Items (Note 1)
				Costs to									Economic			Discontinued
				Achieve,			Crescent			Emission			Hedges			Operations/
	Adjusted			Cinergy			Project			Allowances			(Mark-to-			Extraordinary			Total			Reported
	Earnings			Merger			Impairments			Impairment			Market)*			Items			Adjustments			Earnings
*SEGMENT EARNINGS BEFORE INTEREST AND TAXES* *FROM CONTINUING OPERATIONS*
U.S. Franchised Electric and Gas	$	2,398		$	—		$	—		$	—		$	—		$	—		$	—		$	2,398
Commercial Power	421			—			—			(82		)(F)	(75		)(B)	—			(157		)	264
International Energy	411			—			—			—			—			—			—			411
Total reportable segment EBIT	3,230			—			—			(82		)	(75		)	—			(157		)	3,073
Other	(310		)	(44		)(A)	(214		)(E)	—			—			—			(258		)	(568		)
Total reportable segment and other EBIT	$	2,920		$	(44	)	$	(214	)	$	(82	)	$	(75	)	$	—		$	(415	)	$	2,505
Interest Expense	(741		)	—			—			—			—			—			—			(741		)
Interest Income and Other	127			—			—			—			—			—			—			127
Income Taxes from Continuing Operations	(773		)	17			83			30			27			—			157			(616		)
Discontinued Operations, net of taxes	—			—			—			—			—			16		(C)	16			16
Extraordinary Items, net of taxes	—			—			—			—			—			67		(D)	67			67
Net Loss Attributable to Noncontrolling Interests	(4		)	—			—			—			—			—			—			(4		)
*Net Income (Loss) Attributable to Duke Energy Corporation*	$	1,537		$	(27	)	$	(131	)	$	(52	)	$	(48	)	$	83		$	(175	)	$	1,362
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC*	$	1.21		$	(0.02	)	$	(0.10	)	$	(0.04	)	$	(0.04	)	$	0.07		$	(0.13	)	$	1.08
*EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED*	$	1.21		$	(0.02	)	$	(0.10	)	$	(0.04	)	$	(0.04	)	$	0.06		$	(0.14	)	$	1.07

Note 1 - Amounts for special items are presented net of any related noncontrolling interest.

(A) - $21 million recorded in Operation, maintenance and other and $23 million recorded in Depreciation and amortization (all Operating Expenses) on the Consolidated Statements of Operations.

(B) - $72 million loss recorded within Non-regulated electric, natural gas, and other (Operating Revenues) and $3 million loss recorded within Fuel used in electric generation and purchased power (Operating Expenses) on the Consolidated Statements of Operations.

(C) - Recorded in Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations

(D) - Recorded in Extraordinary Items, net of tax on the Consolidated Statements of Operations.

(E) - Recorded in Equity in earnings (loss) of unconsolidated affiliates on the Consolidated Statements of Operations.

(F)- Recorded in Goodwill and other impairment charges within Operating Expenses on the Consolidated Statements of Operations.

Weighted Average Shares (reported and adjusted) - in millions

Basic		1,265
Diluted		1,267

* Represents the mark-to-market impact of derivative contracts in the non-native portfolio, which is recognized in earnings immediately as such derivative contracts do not qualify for hedge or regulatory accounting, used in Duke Energy’s hedging of a portion of the economic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commodities (e.g. coal, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations of the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement better matches the financial impacts of the hedge contract with the portion of the econor value of the underlying hedged asset. Management believes that the presentation of adjusted diluted EPS Attributable to Duke Energy Corporation provides useful information to investors, as it allows them to more accurately compare the company’s performance across periods.

Duke Energy International

Reported to Adjusted EBIT Reconciliation

(Dollars in Millions)

	Years ended Dec. 31,
	2007		2006
Reported Segment EBIT	$	388	$	163
Special Items:
Settlement Reserves (a)	—		100
Impairment of Campeche Investment (b)	—		50

Adjusted Segment EBIT	$	388	$	313

(a) Recorded in Operation, maintenance and other (Operating Expenses) on the Consolidated Statements of Operations

(b) $33 million recorded in Operation, maintenance and other (Operating Expenses) and $17 million recorded in Losses on sales and impairments of unconsolidated affiliates (Other Income and Expenses) on the Consolidated Statements of Operations.

Duke Energy Corporation

Available Liquidity Reconciliation

(In millions)

Cash and Cash Equivalents	$	1,542

Less: Amounts Held in Foreign Jurisdictions	(613		)
	$	929

Plus: Remaining Availability under Master Credit Facility	1,884

Total Available Liquidity as of December 31, 2009 (a)	$	2,813		(approximately $2.8 billion)

(a) The available liquidity balance presented is a non-GAAP financial measure as it represents the aggregated presentation of cash and cash equivalents and short-term investments (excluding amounts held in foreign jurisdictions), and remaining availability under the master credit facility. The most directly comparable GAAP financial measure for available liquidity is cash and cash equivalents.

Duke Energy Corporation

February 16, 2010 Analysts Meeting

Cash Flow Reconciliation Required by SEC Regulation G

($ in Millions)

		Forecast
		2010
Primary Sources:
Adjusted Net Income (1)	a	$	1,700
Depreciation & Amortization	a	1,800
Deferred and Accrued Taxes	a	600
Total Sources		4,100

Primary Uses:
Capital and Investment Expenditures	b	(5,200		)
Dividends	c	(1,300		)
Total Uses		(6,500		)
Other Sources/ (Uses), net	b	350
Uses in Excess of Sources		(2,050		)
Debt Maturities	c	(775		)
Debt Refinancings	c	(625		)
Required Funding		(3,450		)
Issuances of Debt	c, d	2,275
Cash Received from Equity Issued under Internal Stock Plans	c	400
Utilization of Cash	e	775
Total Financings and Cash Utilization		$	3,450

Reconciliations to amounts per U.S. GAAP reporting:

Operating cash flow components from above [summation of (a)]		$	4,100
Reconciling items to GAAP operating cash flow (2)		(260		)
Net cash provided by operating activities per GAAP Consolidated Statement of Cash Flows		$	3,840

Investing cash flow components from above [summation of (b)]		$	(4,850	)
Reconciling items to GAAP investing cash flow (3)		260
Net cash used in investing activities per GAAP Consolidated Statement of Cash Flows		$	(4,590	)

Financing cash flow components from above [item (c)]		$	(25	)
Reconciling items to GAAP financing cash flow (4)		(15		)
Net cash provided by financing activities per GAAP Consolidated Statement of Cash Flows		$	(40	)

Issuances of Debt from above [item (d)] includes Notes payable and commercial paper which is separately presented per GAAP Consolidated Statements of Cash Flows

Utilization of cash from above [item (e)] is the equivalent of Net decrease in cash and cash equivalents per GAAP Consolidated Statements of Cash Flows

Notes:

(1) The adjusted net income of $1,700 million for 2010 is an illustrative amount based on the midpoint of Duke Energy’s adjusted diluted EPS outlook range of $1.25-$1.30 per share, which is consistent with the 2010 employee incentive earnings target. The EPS measure used for employee incentive bonuses is primarily based on adjusted diluted EPS. Adjusted diluted EPS is a non-GAAP financial measure as it represents diluted EPS from continuing operations attributable to Duke Energy Corporation shareholders, adjusted for the per-share impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Special items represent certain charges and credits which management believes will not be recurring on a regular basis, although it is reasonably possible such charges and credits could recur. Mark-to-market adjustments reflect the mark-to-market impact of derivative contracts, which is recognized in GAAP earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting treatment, used in Duke Energy’s hedging of a portion of the economic value of its generation assets in the Commercial Power segment (as discussed separately under “Adjusted Diluted Earnings per Share (‘EPS’)”). The most directly comparable GAAP measure for adjusted diluted EPS is reported diluted EPS from continuing operations attributable to Duke Energy Corporation common shareholders, which includes the impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Due to the forward-looking nature of this non-GAAP financial measure for future periods, information to reconcile it to the most directly comparable GAAP financial measure is not available at this time, as management is unable to project special items or mark-to-market adjustments for future periods.

(2) Amount consists primarily of an adjustment for operating cash flow items included in the “Other Sources/(Uses), net” which are combined for the GAAP reconciliation in Investing activities (principally equity allowance for funds used during construction and other changes in working capital).

(3) Amount consists primarily of an adjustment for operating cash flow items included in the “Other Sources/(Uses), net” which are combined for the GAAP reconciliation in Investing activities (principally equity allowance for funds used during construction and other changes in working capital). After reclassification of the approximate net ($260 million) of operating cash flow activity, the amount within investing activities from the “Other Sources/(Uses), net” line item primarily reflects proceeds related to planned monetization of certain long-lived assets.

(4) Amount consists primarily of distributions to noncontrolling interests.

Exhibit 99.3

Duke Energy Corporation

Non-GAAP Reconciliations

2010 Investor and Analyst Meeting

February 16, 2010

Adjusted Diluted Earnings per Share (“EPS”)

The materials for Duke Energy Corporation’s (“Duke Energy”) 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of adjusted diluted EPS for the quarters and years ended December 31, 2009 and 2008. Adjusted diluted EPS is a non-GAAP financial measure as it represents diluted EPS from continuing operations attributable to Duke Energy Corporation common shareholders, adjusted for the per share impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Special items represent certain charges and credits which management believes will not be recurring on a regular basis, although it is reasonably possible such charges and credits could recur. Mark-to-market adjustments reflect the mark-to-market impact of derivative contracts, which is recognized in GAAP earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting, used in Duke Energy’s hedging of a portion of the economic value of certain of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commodities (e.g., coal, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations of the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement better matches the financial impacts of the hedge contract with the portion of the economic value of the underlying hedged asset. The most directly comparable GAAP measure for adjusted diluted EPS is reported diluted EPS from continuing operations attributable to Duke Energy Corporation common shareholders, which includes the impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Reconciliations of adjusted diluted EPS for the quarters and years ended December 31, 2009 and 2008 to the most directly comparable GAAP measures are included below.

2010 Adjusted Diluted EPS Outlook

The materials for Duke Energy’s 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of the forecasted 2010 adjusted diluted EPS outlook range of $1.25-$1.30 per share. Additionally, the materials reference the 2009 EPS incentive target of $1.20 per share. The EPS measure used for employee incentive bonuses is primarily based on adjusted diluted EPS. The materials also reference the forecasted range of growth of 4%-6% in adjusted diluted EPS (on a compound annual growth rate (“CAGR”) basis) from a base of adjusted diluted EPS for 2009 of $1.22. Adjusted diluted EPS is a non-GAAP financial measure as it represents diluted EPS from continuing operations attributable to Duke Energy Corporation shareholders, adjusted for the per-share impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Special items represent certain charges and credits which management believes will not be recurring on a regular basis, although it is reasonably possible such charges and credits could recur. Mark-to-market adjustments reflect the mark-to-market impact of derivative contracts, which is recognized in GAAP earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting treatment, used in Duke Energy’s hedging of a portion of the economic value of its generation assets in the Commercial Power segment (as discussed separately under “Adjusted Diluted Earnings per Share (‘EPS’)”). The most directly comparable GAAP measure for adjusted diluted EPS is reported diluted EPS from continuing operations attributable to Duke Energy Corporation common shareholders, which includes the impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Due to the forward-looking nature of this non-GAAP

financial measure for future periods, information to reconcile it to the most directly comparable GAAP financial measure is not available at this time, as management is unable to project special items or mark-to-market adjustments for future periods.

Adjusted Segment EBIT and Other Net Expenses for 2008 and 2009 and Forecasted

Adjusted Segment EBIT and Other Net Expenses for 2010

The materials for Duke Energy’s 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of adjusted segment EBIT and Other net expenses for the quarters and years ended December 31, 2009 and 2008 and a discussion of forecasted 2010 adjusted segment EBIT and Other net expenses. Additionally, reference is made to Duke Energy’s equity method investment in National Methanol Company (a component of the International Energy segment), and its equity method earnings contribution as a percentage of International Energy’s segment EBIT, on an adjusted basis.

The primary performance measure used by management to evaluate segment performance is segment EBIT from continuing operations, which at the segment level represents all profits from continuing operations (both operating and non-operating), including any equity in earnings of unconsolidated affiliates, before deducting interest and taxes, and is net of the income attributable to non-controlling interests. Management believes segment EBIT from continuing operations, which is the GAAP measure used to report segment results, is a good indicator of each segment’s operating performance as it represents the results of Duke Energy’s ownership interests in continuing operations without regard to financing methods or capital structures. Duke Energy also uses adjusted segment EBIT and adjusted Other net expenses (including adjusted equity earnings for Crescent Resources) as a measure of historical and anticipated future segment and Other performance. When used for future periods, adjusted segment EBIT and adjusted Other net expenses may also include any amounts that may be reported as discontinued operations or extraordinary items.

Adjusted segment EBIT and Other net expenses are non-GAAP financial measures as they represent reported segment EBIT and Other net expenses adjusted for the impact of special items and the mark-to market impacts of economic hedges in the Commercial Power segment. Special items represent certain charges and credits which management believes will not be recurring on a regular basis, although it is reasonably possible such charges and credits could recur. Mark-to-market adjustments reflect the mark-to-market impact of derivative contracts, which is recognized in GAAP earnings immediately as such derivative contracts do not qualify for hedge accounting or regulatory accounting, used in Duke Energy’s hedging of a portion of the economic value of certain of its generation assets in the Commercial Power segment (as discussed above under “Adjusted Diluted Earnings per Share (‘EPS’)”). Management believes that the presentation of adjusted segment EBIT and adjusted Other net expenses provides useful information to investors, as it provides them an additional relevant comparison of a segment’s or Other’s performance across periods. The most directly comparable GAAP measures for adjusted segment EBIT and Other net expenses are reported segment EBIT and Other net expenses, which represent segment and Other results from continuing operations, including any special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Reconciliations of adjusted segment EBIT and Other net expenses for the quarters and years ended December 31, 2009 and 2008 to the most directly comparable GAAP measures are included below. Additionally, reconciliations of adjusted segment EBIT for International Energy for 2007 and 2006 to reported segment EBIT are included below. Due to the forward-looking nature of this non-GAAP financial measure for 2010, information to reconcile it to the most directly comparable GAAP financial measure is not available at this time, as management is unable to project special items or mark-to-market adjustments for future periods.

Latin American Portfolio Cash Flows

The materials for Duke Energy’s 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of management’s expectation that the Latin American portfolio of assets will have significant annual free cash flow of approximately $200 million to $300 million. These amounts represent non-GAAP financial measures. This forecast of cash generation primarily reflects expected cash to be provided by operating activities (a GAAP measure), but also reflects certain financing and investing activities. However, this forecast of cash generation specifically excludes capital and investment expenditures.

Ohio Customer Switching Impacts to Diluted Earnings per Share

The materials for Duke Energy’s 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of the fact that the Midwest Generation component of the Commercial Power segment has had certain customers switch away from Duke Energy Ohio’s Electric Security Plan offering to alternative electricity generation providers. Certain of these customers have been acquired by Duke Energy Retail Sales (“DERS”). DERS operates as Duke Energy’s competitive retail arm in Ohio. DERS revenue pricing is generally significantly lower than the revenue pricing under the Electric Security Plan. As of December 31, 2009, approximately 40% of Electric Security Plan customer load has switched to alternative energy providers, and approximately 60% of that switched customer load has been acquired by DERS, for a net switching percentage of approximately 15%. For 2010, Duke Energy forecasts that approximately 45% of customers in Duke Energy Ohio’s Electric Security Plan territory will have switched to alternative energy providers, and after consideration of customers forecasted to be acquired by DERS, the net switching percentage is estimated to be approximately 25% in 2010. This document references the estimated diluted earnings per share impact of net customer switching to be approximately $0.02 per share in 2009, and that such negative impact will be an incremental $0.04 - $0.07 per share in 2010. The estimate of the diluted earnings per share impact of net customer switching is primarily calculated by first multiplying lost Electric Security Plan volume in megawatt-hours (MWh) by the difference between the average Electric Security Plan operating revenue amount per MWh less the average expense per MWh for fuel used in electric generation and purchased power (“Electric Security Plan lost margin”). This Electric Security Plan lost margin amount is then offset by the average gross margin (calculated in a similar manner as described above) earned on additional wholesale market sales forecasted as a result of less generation being dedicated to Electric Security Plan customers. Additionally, Electric Security Plan lost gross margin is further offset by DERS gross margin (operating revenues less purchased power costs). DERS gross margin is primarily derived from contracts related to customer load acquired that were historically supplied under the Electric Security Plan offering. The net of these amounts is then tax affected at an approximate 35% tax rate and divided by weighted-average diluted shares outstanding to determine the estimated impact of customer switching to diluted earnings per share. This calculated estimate of the earnings per share impact of customers switching is meant to approximate the entire impact to diluted earnings per share; however, given the potential indirect effects of customer switching to items such as operation, maintenance and other expenses, management is unable to calculate the exact impact of customer switching to diluted earnings per share.

The impacts of customer switching in 2009 are embedded within the 2009 reported and adjusted diluted earnings per share amounts discussed in the section entitled “Adjusted Diluted Earnings per Share (“EPS”).” The forecasted impacts of customer switching in 2010 are embedded within the 2010 adjusted diluted EPS outlook range of $1.25-$1.30 per share, discussed in the section entitled “2010 Adjusted Diluted EPS Outlook.”

Cash-on-Cash Returns for Certain Renewables Projects

The materials for Duke Energy’s 2010 Investor and Analyst Meeting presentation on February 16, 2010 include a discussion of Duke Energy’s estimate that Renewables projects recently constructed or in the process of construction will earn on average 20%-30% annual cash-on-cash returns over the first five years of operation. The numerator in each annual period in the cash-on-cash returns calculation represents cash flows from operations including production tax credits, if applicable, and tax cash benefits associated with accelerated tax depreciation, including the initial tax basis amount greater than the corresponding book basis amount for projects that have received the investment tax credit (“ITC”) and/or government grant for qualifying renewable energy facilities. Additionally, the numerator in the cash-on-cash returns calculation includes the ITC and/or government grant received when the project is initially placed in service, if applicable. ITC and government grant receipts are classified within cash flows from investing activities in the consolidated statements of cash flows. In summary, the numerator includes all cash inflows and outflows associated with the Renewables projects, except for interest on debt balances that may be associated with Renewables projects. The denominator in the first year of the cash-on-cash returns calculation represents total project capital expenditures. The denominator in each subsequent year of the cash-on-cash returns calculation is reduced by the numerator in the preceding year (i.e., the denominator generally equals cumulative capital expenditures less cumulative net cash inflows). Forecasted annual cash flows in the calculation are not adjusted for the time value of money.