...This document includes forward- looking statements within the meaning of Section 27A of the...

SECOND QUARTER 2012

Earnings Review and Business Update August 2, 2012

Jim Rogers Chairman, President and Chief Executive Officer

Lynn Good Executive Vice President and Chief Financial Officer

Second Quarter Earnings Review and Business Update August 2, 2012

SAFE HARBOR

2

SAFE HARBOR STATEMENT This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management's beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as "anticipate," "believe," "intend," "estimate," "expect," "continue," "should," "could," "may," "plan," "project," "predict," "will," "potential," "forecast," “target,” “outlook,” “guidance,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements, as well as rulings that affect cost and investment recovery or have an impact on rate structures; costs and effects of legal and administrative proceedings, settlements, investigations and claims; industrial, commercial and residential growth or decline in Duke Energy Corporation's (Duke Energy) service territories, customer base or customer usage patterns; additional competition in electric markets and continued industry consolidation; political and regulatory uncertainty in other countries in which Duke Energy conducts business; the influence of weather and other natural phenomena on Duke Energy operations, including the economic, operational and other effects of storms, hurricanes, droughts and tornadoes; the impact on the Duke Energy’s facilities and business from a terrorist attack; the inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, safety, regulatory and financial risks; the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates; unscheduled generation outages, unusual maintenance or repairs and electric transmission system constraints; the performance of electric generation facilities and of projects undertaken by Duke Energy's non-regulated businesses; the results of financing efforts, including Duke Energy's ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy's credit ratings and general economic conditions; declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy's defined benefit pension plans; the level of creditworthiness of counterparties to Duke Energy's transactions; employee workforce factors, including the potential inability to attract and retain key personnel; growth in opportunities for Duke Energy's business units, including the timing and success of efforts to develop domestic and international power and other projects; construction and development risks associated with the completion of Duke Energy's capital investment projects in existing and new generation facilities, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards, as well as the ability to recover costs from ratepayers in a timely manner or at all; the scope of necessary repairs of the delamination of Crystal River Unit No. 3 Nuclear Plant (CR3) could prove more extensive than is currently identified, such repairs could prove not to be feasible, the cost of repair and/or replacement power could exceed our estimates and insurance coverage or may not be recoverable through the regulatory process, the occurrence of any of which could adversely affect Duke Energy’s financial condition, results of operations and cash flows; the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the Progress Energy businesses and realize cost savings and any other synergies expected from the merger and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; the impact of compliance with material restrictions of conditions related to the Progress Energy merger imposed by regulators could exceed our expectations; the impact of business uncertainties during the Progress Energy merger integration process; and the ability to successfully complete merger, acquisition or divestiture plans. Additional risks and uncertainties are identified and discussed in Progress Energy’s and Duke Energy’s reports filed with the SEC and available at the SEC’s website at www.sec.gov. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 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/.

http://www.sec.gov/


Delivering on our commitments

Status of merger integration

Crystal River 3 and major construction projects update

2Q-2012 earnings review and financial update

Regulated utility customer volume trends

Financial impacts of merger

Financial objectives

3

TOPICS FOR TODAY’S CALL

Second Quarter Earnings Review and Business Update August 2, 2012 4

DELIVERING ON OUR COMMITMENTS

Achieve Financial

Objectives

Deliver merger benefits

for all stakeholders

Complete major capital projects

and address Crystal River 3

next steps

Continue operational

excellence of fleet and grid

Obtain constructive regulatory outcomes


HIGHLY EXPERIENCED LEADERSHIP TEAM

Board of Directors (15 Members)

Lynn Good Chief Financial Officer

Marc Manly General Counsel

Lee Mazzocchi Chief Integration and Innovation Officer

Jennifer Weber Chief Human Resources Officer

Dhiaa Jamil Nuclear Generation

Jeff Lyash Energy Supply

Keith Trent Regulated Utilities

Lloyd Yates Customer Operations

Jim Rogers Chairman, President and CEO

Chuck Whitlock Commercial Businesses


MERGER INTEGRATION UPDATE Run-Rate Non-Fuel O&M Synergies

50%

20%

20%

10%

Non-Fuel O&M Focus Area Key Initiatives

Functional Consolidation

Release ~1,100 employees through Voluntary Severance Program Complete staffing process by December 2012 Rationalize real estate portfolio

Systems Consolidation

Consolidate financial IT systems Consolidate HR IT systems Consolidate asset management, work

management and supply chain IT systems Consolidate IT infrastructure (e.g., data centers)

Operational Best Practices

Implement common nuclear, fossil and T&D operating models Implement common nuclear re-fueling services

model Adopt improved project management and

investment governance practices

Supply Chain

Consolidate or renegotiate key procurement contracts Harmonize in-sourcing and out-sourcing

strategies

Supply Chain

Operational Best

Practices

Systems Consolidation

Functional Consolidation


Guaranteed ~$650MM in joint dispatch and fuel savings in the Carolinas over 5 years

~50/50 split between joint dispatch and fuel savings

Joint Dispatch

DEC and PEC operating as one generation fleet since July 2

Fuel Savings

~60% of savings already achieved through renegotiated contracts

Expect further savings through ongoing market opportunities

7

OTHER MERGER COMMITMENTS Joint Dispatch and Fuel Savings FERC Interim Mitigation Plan

Virtual Divestiture Firm capacity and energy sales occurring since

July 2 Potomac Economics independently monitoring

performance daily In compliance with third party agreements

Transmission Projects will increase import

capabilities into Carolinas’ service areas 7 transmission projects at an estimated

cost of $110MM * Projects are on budget and are expected to

be completed by December 2014

On track to deliver on our merger commitments

FERC Permanent Mitigation Plan

* Excludes the acceleration of the Greenville-Kinston Dupont project at an estimated cost of ~$35 million


CRYSTAL RIVER 3 UPDATE

Crystal River Unit 3 Nuclear Power Plant • Citrus County, FL • 860-MW single unit • B&W pressurized water reactor • Operator: PEF (91.78% ownership)

URS Corporation selected in May 2012 as preferred vendor to develop the engineering plan for repair

Final decision to repair or retire the plant has not been made

Entered into non-binding mediation with NEIL that is expected to occur in 4Q 2012

Nuclear safety remains our top priority and the unit remains in a safe and secure condition

8


$3,275 $2,150

$575 $625 $350

$25

$50

$135 $125 $250

9

EDWARDSPORT CLIFFSIDE DAN RIVER CC LEE CC (Wayne County)

SUTTON CC

Jurisdiction Duke Indiana

Duke Carolinas

Duke Carolinas

Progress Carolinas

Progress Carolinas

Technology 618 MW

IGCC

825 MW Advanced Clean Coal

620 MW Combined-Cycle

Gas-Fired


Gas-Fired


Gas-Fired

In-Service Target 1Q 2013 3Q 2012 4Q 2012 1Q 2013 4Q 2013

% Complete 98% Complete 99% Complete 90% Complete 85% Complete 35% Complete

Spent as of 6/30/2012

Estimated expenditures to complete project

1 $ in millions, project costs include direct capital and AFUDC

STATUS OF MAJOR CONSTRUCTION PROJECTS1 (As of 6/30/2012)


2Q-2012 Primary Adjusted Segment Income Drivers USFE&G +$40 million ▲Implementation of new Carolinas rates ▲Lower O&M and governance costs, primarily due to prior year storms ▲Riders and energy efficiency ▼Higher depreciation & amortization expense ▼Less favorable weather ▼AFUDC and interest expense

+$0.09 +$0.14 +$0.08

+$0.03

($0.06) ($0.05) ($0.02)

INTERNATIONAL −$22 million ▼Unfavorable results in Central America ▼Unfavorable foreign currency exchange rates ▲Improved results in Brazil ▲Improved results in Peru

($0.05) ($0.05) ($0.03) +$0.01 +$0.01

COMMERCIAL POWER +$2 million ▼Lower Midwest coal generation volumes and margin, partially offset by capacity revenues ▼Lower Duke Energy Retail volumes and margins ▲Midwest coal stability charge revenues ▲Recovery of Lehman Brothers receivable previously written off ▲Lower O&M related to generation fleet ▲Effect of prior year Vermillion impairment

+$0.00 ($0.07)

($0.03) $0.05 $0.02

$0.02 $0.01

$0.99 $1.02

$2.17 $2.16

2Q 2011 2Q 2012 YTD 2011 YTD 2012

2012 Status

On-Track to Achieve $4.20 - $4.35 EPS*

Adjusted Diluted EPS

* Based on adjusted diluted EPS; original guidance range of $1.40 - $1.45 has been adjusted for the 1-for-3 reverse stock split

2Q-2012 EARNINGS SUMMARY AND DRIVERS


Carolinas – 2Q12 vs. 2Q11 Midwest – 2Q12 vs. 2Q11 Total – 2Q12 vs. 2Q11

2Q-2012 weather-normalized load growth showed modest improvement Industrial load continues its recent strength

Automotive and heavy machinery sectors remain strong Weakness in primary and fabricated metals sector in Midwest and textiles in Carolinas

Residential and commercial classes remain challenged Economic development activities continue Economic conditions in Carolinas and Midwest are stable, but customers remain cautious about the future

Residential

Commercial

Industrial

Total 1.3%

3.0%

0.9%

0.5%

1.1%

2.6%

0.6%

0.1%

1.3%

2.8%

0.8%

0.3%

USFE&G Weather-Normalized Volume Trends (% Change)

USFE&G WEATHER-NORMAL VOLUME TRENDS


$1.22 $1.23

Original 2012 Adjusted Diluted EPS

Guidance Range

Progress Contribution

Share Dilution

Updated 2012 Adjusted Diluted EPS

Guidance Range

$4.20 – $4.35

$4.20 – $4.35

12

UPDATED 2012 ADJUSTED DILUTED EPS GUIDANCE RANGE

Continue to target 2012 adjusted diluted EPS guidance range of $4.20 - $4.35

Merger expected to result in incremental goodwill of ~$12 billion

Expect accounting charges (2) of ~$450-$550 million, which will primarily be incurred in the second half of 2012 and treated as a special item

(1) Adjusted Diluted EPS Guidance Range (2) Charges principally relate to employee severance costs, costs related to the FERC interim and permanent mitigation plans, concessions agreed to with the Carolinas commissions in order to

receive merger approval, and merger transaction costs Note: Amounts not to scale

Original 2012 Range (1)

Merger Impacts & Forecast Updates

Increase in Shares

Updated 2012 Range (1)

Net Income ( $ millions) / Average shares (MM)

$1,905 446

$545 446

$2,450 $2,450 575 446

$2,450 575 -


FINANCIAL OBJECTIVES

13

Current year earnings guidance

Long-term earnings growth

Dividend growth

Balance sheet

strength

Achieve earnings guidance range of $4.20 - $4.351

Target long-term adjusted diluted EPS growth of

4% to 6%

Continue growing the dividend within a 65% - 70% target payout ratio1

Maintain strong, investment-grade credit ratings

(1) Based upon adjusted diluted EPS


Item Slides Key 2012 Assumptions 15-19 Duke Energy 2Q-2012 Earnings Supplement 20-34 Duke Energy Overview 35-37 Additional Financial Information 38-44 Environmental Overview 45-50 Progress Energy 2Q-2012 Earnings Supplement 51-55

APPENDIX MATERIALS


KEY 2012 ASSUMPTIONS


Duke Ohio (including Duke Kentucky)

Progress Carolinas

Duke Carolinas

16

Progress Florida

Duke Indiana

DUKE ENERGY

U.S. FRANCHISED ELECTRIC AND GAS

North and South Carolina

North and South Carolina

Florida

Indiana

Ohio T&D

Ohio Gas Distribution

Kentucky Electric and Gas

COMMERCIAL POWER

Duke Energy Renewables

Duke Energy Retail

Midwest Coal Generation

Midwest Gas Generation

INTERNATIONAL

BUSINESS SEGMENT STRUCTURE


UPDATE ON KEY 2012 ASSUMPTIONS

($ in Millions) Duke Standalone 2012

Assumptions

Impact of Progress Merger

and Updates1

2012 Assumptions, including Progress

Merger1

2012 YTD (thru 6/30/12)2

Adjusted Segment Income:

USFE&G $1,485 $605 $2,090 $681

Commercial Power $80 $20 $100 $62

International $410 $10 $420 $247

Other (3) ($70) ($90) ($160) ($28)

Duke Energy Consolidated (4) $1,905 $545 $2,450 $962

Average Shares Outstanding (in millions) 575 446

Additional Consolidated Information:

Interest Expense $940 $335 $1,275 $456

Adjusted Effective Tax Rate 31% 36% 31% - 32% 31%

Debt AFUDC and Capitalized Interest $125 $45 $170 $74

AFUDC Equity $205 $65 $270 $116

Capital Expenditures $4,300 – $4,500 $1,200 $5,500 - $5,700 $2,297

17

(1) Includes Progress Energy forecast for 3Q 2012 and 4Q 2012 (2) Duke Energy standalone results only; Progress Energy 1Q 2012 and 2Q 2012 results are not included (3) Note that governance costs that were previously included in “Other” have now been allocated to the USFE&G, Commercial Power and International business segments (4) Adjusted Net Income based upon midpoint of adjusted diluted EPS guidance range


CAPITAL EXPENDITURE PROFILE

($ in Millions)

Duke Standalone 2012 Assumptions

Impact of Progress Merger and Updates1

2012 Assumptions, including Progress Merger1

Edwardsport IGCC 150$ -$ 150$ Cliffside 150 - 150 CC / CT Additions 200 150 350 Grid Modernization 125 50 175 Transmission & Distribution Growth - 150 150 Environmental 200 (50) 150 Nuclear Fuel 300 100 400 Lee Nuclear, Nuclear Uprates, & Other 150 150 300 Customer Additions 250 50 300 Maintenance & Other 1,875 500 2,375

US FE&G Capital 3,400$ 1,100$ 4,500$

Renewable Growth 500$ -$ 500$ Maintenance 175 - 175 Commercial Transmission 25 - 25 Cost to Achieve - 75 75 Other (2) 200 25 225

Commercial Businesses & Other Capital 900$ 100$ 1,000$

Total Discretionary Growth Capital 200$ -$ 200$ Total Capital Expenditures $ 4,300 - 4,500 1,200$ $ 5,500 - 5,700

18

(1) Includes Progress Energy forecast for 3Q 2012 and 4Q 2012 (2) Comprised primarily of Other Segment capital and Midwest Generation environmental capital


($ in Millions)

Duke Standalone 2012 Assumptions

Impact of Progress Merger and Updates1

2012 Assumptions, including Progress Merger1

EnvironmentalDuke Carolinas 25$ -$ 25$ Progress Carolinas - 20 20 Florida - 30 30 Indiana 175 (100) 75 Kentucky - - - Total Environmental 200$ (50)$ 150$ Customer AdditionsDuke Carolinas 200$ -$ 200$ Progress Carolinas - 30 30 Florida - 20 20 Indiana 25 - 25 Ohio 25 - 25 Total Customer Additions 250$ 50$ 300$ MaintenanceDuke Carolinas 1,250$ -$ 1,250$ Progress Carolinas - 325 325 Florida - 175 175 Indiana 355 - 355 Ohio 210 - 210 Kentucky 60 - 60 Total Maintenance and Other 1,875$ 500$ 2,375$

SELECT FE&G CAPITAL EXPENDITURES, BY LEGAL ENTITY

(1) Includes Progress Energy forecast for 3Q 2012 and 4Q 2012


DUKE ENERGY 2Q-2012 EARNINGS SUPPLEMENT


Adjusted segment income was flat primarily due to:

• +$0.23 – implementation of new Carolinas rates • +$0.13 – lower O&M costs • +$0.05 – riders and energy efficiency

Partially offset by: • -$0.18 – unfavorable weather • -$0.09 – higher depreciation & amortization expense • -$0.04 – AFUDC and interest expense $100

$200 $300 $400 $500

Q1 Q2 Q3 Q4

USFE&G Adjusted Segment Income

2011 2012

(in millions) YTD 2012 vs. YTD 2011 Drivers

21

Reported & Adjusted Segment Income

($ in Millions) 2Q12 2Q11 YTD 2012 YTD 2011

Reported Segment Income $ 337 $ 297 $473 $638

Adjustments -- -- 208 --

Adjusted Segment Income $ 337 $ 297 $681 $638

US FRANCHISED ELECTRIC AND GAS

YTD 2012 Adjustments, net of tax: • $268 million – Edwardsport impairment, net of tax • ($60) million – Voluntary Opportunity Plan deferral, net of tax Note: all amounts are for standalone Duke Energy and do not

include the results of Progress Energy for 1Q or 2Q 2012


Volume trends are on a weather-normalized basis; Extra day due to leap year is included in 1Q 2012 volumes

22

1.6%

-0.6%

1.2% 0.3% 0.3% 0.5%

2Q11 3Q11 4Q11 1Q12 2Q12 2012 Plan

Residential Change vs. Prior Year Quarter

0.0%

2.1%

-0.6%

2.6% 2.8% 1.0%

2Q11 3Q11 4Q11 1Q12 2Q12 2012 Plan

Industrial Change vs. Prior Year Quarter

-0.7%

0.2%

-0.1%

0.6% 0.8% 1.0%

2Q11 3Q11 4Q11 1Q12 2Q12 2012 Plan

Commercial Change vs. Prior Year Quarter

0.2% 0.4% 0.2%

1.0% 1.3%

0.7%

2Q11 3Q11 4Q11 1Q12 2Q12 2012 Plan

USFE&G Total Change vs. Prior Year Quarter

NORMALIZED VOLUME TRENDS – USFE&G


70%

80%

90%

100%

1Q 2Q 3Q 4Q

Nuclear Generation Capacity Factor

2012 Year-End Target Actual

70%

80%

90%

100%

1Q 2Q 3Q 4Q

Fossil Generation Commercial Availability


$10 $15 $20 $25 $30

1Q 2Q 3Q 4Q

Nuclear Total Operating Cost – $/MWh


$10 $20 $30 $40 $50

1Q 2Q 3Q 4Q

Total Fossil Production Costs – $/MWh


(1) All 2012 actual numbers are presented on a YTD basis

MAINTAIN FOCUS ON OPERATIONAL PERFORMANCE1


Weather Segment Income to Normal: 2012 2011

First Quarter ($0.11) $0.01 Second Quarter $0.03 $0.08 Third Quarter $0.12 Fourth Quarter ($0.08) Year-to-Date ($0.08) $0.13

Key Weather Data (2Q 2012) ►Heating Degree Days

Carolinas – 161 (22% lower than normal) Midwest – 172 (24% lower than normal)

►Cooling Degree Days Carolinas – 526 (5% higher than normal) Midwest – 460 (37% higher than normal)

(EPS Impact)

Note: Favorable/(Unfavorable); Amounts may not foot due to rounding

24

USFE&G QUARTERLY WEATHER IMPACTS


No NEIL receivable recorded associated with the second delamination

Accounting standards require insurance receivable to be probable of full recovery

NEIL: Nuclear Electric Insurance Limited, a mutual insurance company Insurance coverage limits per event are as follows: • Property damage - $2.25 billion • Replacement power - $490 million

$-

$50

$100

$150

$200

$250

$300

$350

Spent to

Date

NEIL Proceeds Received

Balance for Base Rate Recovery

$305 ($143)

Repair Costs

$-

$100

$200

$300

$400

$500

$600

Spent to

Date

NEIL Proceeds Received

Balance for Clause Recovery

$372

$534 ($162)

Replacement Power Costs

Florida Public Service Commission unanimously approved comprehensive settlement agreement which provides regulatory recovery guidelines related to unit

Continuing discussions with NEIL for full recovery associated with the second delamination

($M) ($M)

*

*Balance to be recovered through annual fuel clause proceeding.

$162

CRYSTAL RIVER UNIT 3 NUCLEAR OUTAGE (As of 6/30/2012)

25


OVERVIEW OF DUKE ENERGY OHIO RATE CASES

Electric Distribution Rate Case Highlights

Retail revenue increase requested ~$87 MM (5.1%)

Proposed rate base ~$1.1 B

Return on equity requested 10.6%

Equity component of capital structure 53%

Rates expected to be in effect 2Q 2013

Gas Distribution Rate Case Highlights

Retail revenue increase requested ~$45 MM (8.1%)

Proposed rate base ~$900 MM

Return on equity requested 10.6%

Equity component of capital structure 53%

Rates expected to be in effect 2Q 2013


Jurisdiction 2012 2013 Status DEC – North Carolina

DEC – South Carolina

PEC – North Carolina

PEC – South Carolina

Florida

Under the settlement agreement approved by the FPSC, PEF will not petition for an increase in base rates that would take effect prior to the first billing cycle for January 2017. If PEF’s ROE falls below 9.5% at any time during the term of the settlement, PEF may seek a base rate increase.

Indiana As part of the Edwardsport settlement agreement reached with key consumer groups on 4/1/12, which remains subject to IURC approval, Duke Indiana agrees not to file a base rate increase prior to March 2013, with rates in effect no earlier than 4/1/14

Ohio – Electric T&D On 6/7/12, filed 30-day notification of intent to file rate case. On 7/20/12, filed rate case testimony. New rates are expected to be in effect in 2Q 2013.

Ohio – Gas On 6/7/12, filed 30-day notification of intent to file rate case. On 7/20/12, filed rate case testimony. New rates are expected to be in effect in 2Q 2013.

Kentucky – Electric As a part of the Kentucky Commission’s approval of the merger on 8/2/11, Duke Kentucky agreed to not file for a base rate increase for two years from the date of the Commission’s order Kentucky – Gas

File Second Half 2012


Filed Mid-2012 Split historical and forward Test Period

Filed Mid-2012 Split historical and forward Test Period


NEAR-TERM RATE CASES TO RECOVER COSTS (As of 8/2/12)

27


North Carolina

South Carolina Florida Indiana Ohio

Electric Gas Kentucky

Electric Gas Current Rate Base in Rates

$7.2B (PEC) $14.5B (1) (DEC)

$10.6B $5.6B $1.3B (2) $700M $600M (3) $200M (4)

Current Allowed ROE 12.75% (PEC) 10.50% (DEC)

12.75% (PEC) 10.50% (DEC)

10.50%(5) 10.50% 10.63%

per settlement (6)

N/A per

settlement

N/A per

settlement 10.375%

Current Allowed Equity 44.0% (PEC) (7)

53.0% (DEC) 44.72% (PEC) (7)

53.0% (DEC) 52.0% 44.44% (8)

N/A per settlement

(9) 55.76% 51.0% 50.8%

Effective Date of Most Recent Rates

8/5/88 (PEC) 2/1/12 (DEC)

8/31/88 (PEC) 2/6/12 (DEC)

2/10/10 5/24/04

Distribution: 7/8/09

ESP: 1/1/2012

7/1/08 1/1/07 1/1/10

Fuel Clause Updated Annually (PEC and DEC)

Annually (PEC and DEC)

Annually Quarterly N/A Monthly Monthly Monthly

Environmental Clause Updated N/A N/A Annually Semi-

Annually N/A N/A N/A N/A

Nuclear Clause/Rider Updated N/A

Not currently active

(PEC and DEC) Annually N/A N/A N/A N/A N/A

Footnotes: (1) Includes state allocable share of $1B Cliffside CWIP in NC and $1.6B Cliffside CWIP in SC (2) Includes approximately $0.4 billion in transmission being recovered through formula rates (3) Kentucky allows recovery on total capitalization instead of rate base (4) Reflects only the investment subject to KPSC jurisdiction (5) Represents the mid-point of an authorized range from 9.5% to 11.5% (6) Ohio’s base distribution rate order is silent on the approved ROE but does specify the ROE that would be used for any riders. (7) The capital structure associated with the 1988 rate orders included approximately 7.5% in preferred stock (8) Indiana’s capital structure includes accumulated deferred income taxes (ADIT). When ADIT is excluded, resulting cap structure approximates 53% equity. (9) Settlement reflects a 58% common equity amount per the “actual adjusted capital structure” but does not specify 58%

CURRENT RATE INFORMATION

REGULATORY OVERVIEW (As of 8/2/12)

28


North Carolina

South Carolina Florida Indiana

Ohio Electric Gas

Kentucky Electric Gas

Notice of Intent Required? Yes Yes Yes Yes Yes Yes Yes Yes

Notice Period 30 Days 30 Days 30 Days Varies 30 Days 30 Days 28 Days 28 Days

Test Year Historical Historical Historical Historical

Partially Projected Partially

Projected Forecast Optional

Forecast Optional

Time Limitation Between Cases No 12 months No 15

Months No No No No

Rates Effective Subject to Refund

7 Months After Filing

6 Months After Filing (10)


N/A 9 Months After Filing




RATE CASE FILING REQUIREMENTS

Footnotes: (10) If the South Carolina Commission fails to rule on a rate case filing within 6 months, the new rates can be implemented and are not subject to refund

REGULATORY OVERVIEW, CONT. (As of 8/2/12)

29


Delivery Period Begins

Jan 2012 June 2013 June 201417 Months 33 $49.72 3329 Months 33 $51.10 33 3341 Months 34 $57.08 34 34 34

May-12 24 months 17 $52.14 17 17Nov-12 24 months 16 16 16May-12 12 Months 17 17Nov-12 12 Months 16 16

Total Tranches Delivered in Year 100 100 100

Dec-11

Auction Date Contract Duration # Tranches to Procure

ClearingPrice

30

Auction Highlights Descending-price clock auction format; administered by independent third-party Each tranche represents 1% of the hourly, load-following full-requirements of Duke Energy Ohio’s SSO load

* Subject to change per review by the Public Utilities Commission of Ohio

DUKE OHIO COMPETITIVE AUCTION SCHEDULE AND RESULTS*


$25

$75

$125

$175

Q1 Q2 Q3 Q4

International Adjusted Segment Income

2011 2012

Adjusted segment income decreased primarily due to:

• -$0.06 – unfavorable results in Central America • -$0.04 – unfavorable foreign currency exchange rates • -$0.02 – unfavorable results in Peru

Partially offset by: • +$0.06 – favorable results in Brazil • +$0.03 – favorable results at NMC

(in millions) YTD 2012 vs. YTD 2011 Drivers

31



Reported Segment Income $ 105 $ 127 $ 247 $ 255

Adjustments -- -- -- --

Adjusted Segment Income $ 105 $ 127 $ 247 $ 255

INTERNATIONAL

Note: all amounts are for standalone Duke Energy and do not include the results of Progress Energy for 1Q or 2Q 2012


COMMERCIAL POWER

$0

$50

$100

Q1 Q2 Q3 Q4

Commercial Power Adjusted Segment Income

2011 2012


• -$0.13 – lower Midwest coal generation volumes and margin, partially offset by capacity revenues

• -$0.07 – lower Duke Energy Retail volumes and margins Partially offset by:

• +$0.08 – Midwest coal stability charge revenues • +$0.02 – higher Midwest gas generation volumes and margins, partially offset

by lower capacity revenues • +$0.02 – lower O&M related to generation fleet • +$0.02 – recovery of Lehman Brothers receivable previously written off • +$0.01 – effect of prior year Vermillion impairment

(in millions)

YTD 2012 vs. YTD 2011 Drivers

32

YTD 2012 Adjustments, net of tax: • $3 million - market-to-market losses on economic hedges



Reported Segment Income $ 28 $ 30 $ 59 $ 79

Adjustments 4 -- 3 3

Adjusted Segment Income $ 32 $ 30 $ 62 $ 82



$55

$23

$85

$132

$-

$25

$50

$75

$100

$125

$150

5,000

5,500

6,000

6,500

2012 2013 2014 2015

Capa

city P

rice p

er M

W-d

ay

Capa

city O

ffere

d (M

W)

Duke MW's Price

2015/2016 Auction Results:

• ~5,800 MWs receives Base Residual Auction pricing

DUKE ENERGY OHIO – PJM CAPACITY AUCTION RESULTS

PJM Planning Year

Capacity Price per MW-day

2011 / 2012 $110 2012 / 2013 $16 2013 / 2014 $28 2014 / 2015 $126 2015 / 2016 $136

Calendar Year


-$50 -$25

$0 $25 $50

Q1 Q2 Q3 Q4

Other Adjusted Income (Loss)

2011 2012

(in millions)

34

YTD 2012 Adjustments, net of tax: • $13 million - costs-to-achieve Progress Energy merger

YTD 2011 Adjustments, net of tax: • $13 million - costs-to-achieve Progress Energy merger

Reported & Adjusted Income (Loss)


Reported Net Expense $ (25) $ (19) $ (41) $ (26)

Adjustments 7 4 13 13

Adjusted Net Expense $ (18) $ (15) $ (28) $ (13)

OTHER


• -$0.01 – higher parent company interest expense

YTD 2012 vs. YTD 2011 Drivers



DUKE ENERGY OVERVIEW


Fuel Type

Natural Gas Hydro Wind Coal / Oil Solar

Brazil 2,119 MW

Guatemala 366 MW

Ecuador 163 MW

Peru 810 MW

Wind – 1,072 MW

Argentina 523 MW

El Salvador 296 MW

Solar – 56 MW

Midwest generation – 6,919 MW

Commercial Businesses (Non-Regulated) US Franchised Electric and Gas (Regulated)

Equity investment in National Methanol (NMC) – Saudi Arabia

Market Capitalization (as of 8/1/2012) ~ $47B Total Assets (pro forma as of 6/30/2012) Over $100B U.S. Generation Capacity ~58GW1

Regulated Electric Customers 7.1 million

Duke Energy Facts

(1) Excludes approximately 4.3 GW of Duke Energy International assets

DUKE ENERGY OVERVIEW (Pro Forma as of 6/30/2012)


Regulated Business Commercial Businesses U.S. Franchised Electric & Gas International Commercial Power • ~49,500 MW of regulated generation • Electric transmission & distribution to

7.1 million customers in 6 states (NC, SC, FL, IN, OH and KY)

• Natural gas distribution to 500,000 customers in OH and KY

• ~4,300 MW of Latin American generation assets (primarily Brazil & Peru)

• Investment in National Methanol

• ~6,900 MW of unregulated generation • ~3,500 MW coal • ~3,400 MW gas/oil

• Renewables business • ~1,100 MW wind • ~50 MW solar

37

(1) Forecasted 2012 adjusted segment Net Income contribution (based upon midpoint of 2012 adjusted diluted EPS range of $4.20 - $4.35), plus Progress Energy results for the six months ended June 30, 2012. (2) Pro forma capacity owned as of 6/30/2012. Excludes approximately 4,300 MW of Duke Energy International assets. Actual generation is for the year-ended 12/31/2011.

90% 16% 4%

-10%

Duke Energy Business Mix1

Regulated

International

Commercial Power

Duke Energy U.S. Generation Mix2

Coal Gas/Oil

Nuclear Hydro/Renewables

51%

40%

29%

16%

18%

36% 8% By Owned Capacity

By Actual Generation

DUKE ENERGY OVERVIEW, CONT. (Pro Forma as of 6/30/2012)

Other


ADDITIONAL FINANCIAL INFORMATION


DISCLOSURE TIMELINE

3Q-2012 Earnings Call

1Q-2013 Analyst Day

Long-Term Growth Rate

Significant Long-Term Growth Drivers

2013 Adjusted Diluted EPS Guidance Range

Significant Year-Over-Year Earnings Drivers

2013 Net Income by Business Segment

2013 Load Growth Assumptions

2013 Cash Flows and Financing Assumptions

2013 Credit Metric Assumptions

3 Year O&M Growth Assumptions

3 Year Capex Assumptions

3 Year Rate Base Growth Assumptions

Merger Synergies Assumptions


(1) Illustrative based upon midpoint of updated 2012 adjusted diluted EPS range to reflect Progress Energy merger

(2) Working capital changes and non-cash AFUDC equity (3) Includes projected changes in short-term debt and commercial paper (4) Excludes potential tax-exempt refundings/refinancings (5) Planned Renewables’ issuances are non-recourse project financings (6) Includes ~$1 billion of debt issuances related to the recapitalization of Duke Energy Ohio in

connection with the expected transfer of generating assets to an affiliate

40

Expected 2012 Financing Plan

Certain treasury strategies could change actual 2012 financing levels (e.g., prefunding 2013 requirements, commercial paper, utilization of cash on hand, etc.)

No equity is planned to be issued in 2012

($ in Millions) 2012EPrimary Sources:

Adjusted Net Income (1) 2,450$ Depreciation & Amortization 2,660 Deferred and Accrued Taxes 1,130 Other Sources / (Uses), net (2) (1,445)

Total Sources 4,795 Primary Uses:

Capital Expenditures (including discretionary) (5,600) Dividends (1,745) Pension Plan Contributions (285)

Total Uses (7,630) Uses in Excess of Sources (2,835)

Debt Maturities (2,810) Required Funding (5,645)

Debt Issuances 4,880 Equity issued from internal plans - Utilization of cash 765

Total Financings and Cash Utilization 5,645$

2012 SUMMARY CASH FLOWS AND FINANCING PLAN

($ in Millions)Estimated Debt

Issuances -- Full Yr 2012 (3) (4)

CompletedEstimated Debt

Issuances -- 2nd Half 2012

DE Carolinas 650$ -$ 650$

PE Carolinas - - -

PE Florida 650 - 650

DE Ohio - - -

DE Indiana 250 250 -

DE Kentucky - - -

Renewables (5) 475 - 475

DEI 255 140 115

Duke Energy (6) 2,600 - 2,600

Total 4,880$ 390$ 4,490$


Duke Energy dividend policy Continued growth in dividend at a rate

slower than growth of adjusted diluted EPS Targeting a long-term payout range of 65%

to 70% of adjusted diluted EPS

Dividend supported by strong regulated earnings base Duke Energy has an 86-year history of consecutive quarterly cash dividend payments Current dividend yield of 4.5%

Note: Annual dividends reflect annualized Q4 dividend per share for each year; 2012 projected dividend is subject to Board discretion; dividend amounts have been adjusted to reflect the 1-for-3 reverse stock split conducted on July 2, 2012; current dividend yield as of Aug. 1, 2012

$2.64 $2.76

$2.88 $2.94

$3.00 $3.06

2007A 2008A 2009A 2010A 2011A 2012E

DUK Annual Dividend Per Share History

* Since spin-off of Spectra Energy

DIVIDEND POLICY


Duke Energy

DE Carolinas

PE Carolinas PE Florida

DE Indiana

DE Ohio

DE Kentucky Total

Master Credit Facility (1) 1,750$ 1,250$ 750$ 750$ 750$ 650$ 100$ 6,000$

Regional Bank Credit Facility (2) 100 100 - - - - - 200 Less: Notes Payable and Commercial Paper (3) (719) (300) - (144) (216) - - (1,379)

Drawdown of Regional Credit Facility (75) - - - - - - (75) Outstanding Letters of Credit (LOCs) (55) (7) (2) (1) - - - (65)

Tax-Exempt Bonds - (95) - - (81) (84) - (260)

Available Capacity 1,001$ 948$ 748$ 605$ 453$ 566$ 100$ 4,421$

Cash & Short-Term Investments (4) 495

Total Available Liquidity 4,916$

($ in millions)

Liquidity (Pro Forma as of June 30, 2012)

(1) Master Credit Facility supports tax-exempt bonds, LOCs and the Duke Energy commercial paper program of $2.2 billion; upon closing of the Progress Energy merger, an incremental $2 billion of Master Credit Facility capacity became effective and is reflected in the amounts above

(2) Regional credit facility supports Duke Energy Corp. and Duke Energy Carolinas (3) Includes permanent layer of commercial paper of $450 million, which is classified as long-term debt, plus other commercial paper loaned to subsidiaries (4) Excludes certain cash and short-term investments in foreign jurisdictions of approximately $1.3 billion

42

DUKE ENERGY LIQUIDITY


Commercial Paper and LT Financings

Project / International Financings

Money Pool and LT Financings

Duke Energy (HoldCo)

Duke Energy Carolinas

Duke Energy International

Duke Energy Ohio

Duke Energy Kentucky

Duke Energy Indiana

Cinergy Corp. (HoldCo)

Duke Energy Renewables and

Other

Progress Energy (HoldCo) *

Progress Energy Carolinas

Progress Energy Florida

SIMPLIFIED FINANCING STRUCTURE

43

* Progress Energy has long-term debt outstanding, but no future issuance is planned at this financing entity


Fitch Moody's S&P DUKE ENERGY Stable Stable Negative Corporate Credit Rating / Issuer Rating BBB+ Baa2 BBB+ Senior Unsecured Debt BBB+ Baa2 BBB Commercial Paper F-2 P-2 A-2 PROGRESS ENERGY Stable Stable Negative Senior Unsecured Debt BBB Baa2 BBB DUKE CAROLINAS Stable Stable Negative Senior Secured Debt A+ A1 A Senior Unsecured Debt A A3 BBB+ PROGRESS CAROLINAS Stable Stable Negative Senior Secured Debt A+ A1 A Senior Unsecured Debt A A3 BBB+ Preferred Stock BBB+ Baa2 BBB- PROGRESS FLORIDA Negative Stable Negative Senior Secured Debt A A2 A Senior Unsecured Debt A- Baa1 BBB+ Preferred Stock BBB Baa3 BBB- DUKE ENERGY INDIANA Stable Stable Negative Senior Secured Debt A A2 A Senior Unsecured Debt A- Baa1 BBB+ DUKE ENERGY OHIO Stable Stable Negative Senior Secured Debt A A2 A Senior Unsecured Debt A- Baa1 BBB+ DUKE ENERGY KENTUCKY Stable Stable Negative Senior Unsecured Debt A- Baa1 BBB+

44

CREDIT RATINGS (As of 8/2/2012)


ENVIRONMENTAL OVERVIEW


Regulates coal combustion residuals (e.g., coal ash) New rule proposed in June 2010 Final rule not expected before 2013

46

Coal Combustion Residuals Rule (CCR)

Regulates SO2 and NOx Rule stayed on December 30, 2011 by DC Circuit Court Oral arguments April 13, 2012 with decision 3rd Qtr 2012 Duke Energy continues to comply with CAIR

Utility boiler Maximum Achievable Control Technology (MACT) rule regulating Hazardous Air Pollutants (e.g., mercury & non-mercury HAPs) EPA published final rule on February 16, 2012 Compliance deadline April 16, 2015 with possible one-year extension EPA reconsideration of new unit emission standards

Targets minimizing the impact to aquatic life from the location or operation of cooling water intake structures New rule proposed in April 2011 EPA to finalize rule in June 2013 per modified settlement agreement

Rule Overview Potential Impacts to Duke Energy

Close or upgrade wet ash ponds Upgrade wet ash handling to dry New wastewater treatment

Mercury and Air Toxics Rule (MATS)

Additional air emissions control equipment Timing of unit retirements in advance

of current plans

Cross-State Air Pollution Rule

(CSAPR)

Potential for timing of unit retirements in advance of current plans Compliance operating challenges

beginning 2013 or later

316(b) Cooling Water Intake Structures Rule

Modification of existing cooling water intake structures or cooling tower installations Timing of unit retirements in advance of

current plans

Greenhouse Gas New Source Performance

Standard (GHG NSPS)

Regulates CO2 emissions for new pulverized coal, IGCC and combined-cycle gas facilities that commence construction after April 2012 New rule proposed in April 2012; final rule not expected before 2013 Proposed standard of 1,000 lbCO2/MWh gross

Affects technology selection for new generation

PENDING ENVIRONMENTAL REGULATIONS


Coal Combustion Residuals Rule

(Coal Ash)

Cross-State Air Pollution Rule

Mercury and Air Toxics Rule

Cooling Water Intake Structures Rule

Major Regulations Duke Energy Domestic Generation (6/30/12 Pro Forma) Considerations for EPA

Transition period must be reasonable to allow utilities time to comply with the new rules Plant closures could

cause a strain on reliability Flexibility should be

maintained to help keep the cost of compliance at a reasonable level

Coal Generation Profile

Steam Generation Cooling Water Intake Profile

Scrubbed and SCR Scrubbed, No SCR (3)

Once-Through Cooling, Unscrubbed Coal

TODAY – 40.9 GW (1) POST MODERNIZATION (2) – 40.3 GW

48%

10% 2%

40% 49%

2%

49%

Once-Through Scrubbed Coal/Nuclear (3) Closed-Cycle Cooling

No Scrubber, No SCR – Under Evaluation

77%

19% 4%

61% 17%

18% 4%

TODAY – 23.0 GW (1) POST MODERNIZATION (2) – 20.2 GW

(1) Reflects already completed retirements of Edwardsport 6-8 (160 MW); Buck 3-4 (113 MW); Cliffside 1-4 (198 MW); Dan River 1-3 (276MW); Gallagher 1,3 (280MW) per Consent Decree; Weatherspoon 1-3 (177 MW); and Bartow 1-3 (440 MW)

(2) Reflects Cliffside 6, Dan River CC, Edwardsport IGCC, Lee CC and Sutton CC in-service as well as potential future retirements (3) Includes Gallagher 2&4, which are retrofitted with baghouse

PENDING EPA REGULATIONS WILL IMPACT U.S. GENERATION

Potential Retirements

Potential Retirements


0% 20% 40% 60% 80% 100% Scrubbed and SCR Scrubbed, No SCR No SCR/Scrubber

Riverbend ~450MW potential to be retired by 2015 Lee ~370MW potential to convert to gas or retire by 2015 Buck 5&6 ~260MW potential to be retired by 2015

Wabash River ~350 MW potential to be retired by 2015 Wabash River ~320 MW potential to convert to gas or retire by 2015

Miami Fort 6 ~165MW potential to be retired by 2015

Beckjord ~860MW potential to be retired by 2015

Coal Generation Profile – Pro Forma as of 6/30/12 Duke Carolinas ~7.0 GW

Plans for Coal Generation Without Controls

1.1 GW 2.5 GW 3.4 GW

1.4 GW

2.7 GW

0.4 GW

0.9 GW

0.9 GW

0.2 GW

48

Notes:(1) All amounts represent approximate owned summer rating capacity (2) Environmental control plans are per the respective jurisdictional 2011/2012 IRPs and are subject to change (3) Duke Energy Carolinas retirement plans reflect meeting the requirements of the January 2012 Settlement Agreement for Cliffside Unit 6. Agreement requires, in varying blocks of MWs and dates, the ultimate retirement of 1,667 MWs of coal-fired generation by December 31, 2020. (4) Progress Energy Florida retirement plans reflect meeting the requirements of the agreement for CAVR compliance. Agreement requires either the retirement of, or retrofit with environmental

controls on Crystal River Units 1-2 (~875 MW) by the completion of the first fuel cycle of the planned Levy Nuclear facility. (5) Reflects already completed retirements of Edwardsport 6-8 (160 MW); Buck 3-4 (113 MW); Cliffside 1-4 (198 MW); Dan River 1-3 (276MW); Gallagher 1,3 (280 MW) per Consent Decree;

Weatherspoon 1-3 (177 MW); and Bartow 1-3 (440 MW)

* Includes Gallagher 2&4, which are retrofitted with baghouse

POSITIONING OUR COAL FLEET FOR EPA REGULATIONS

Progress Carolinas ~4.8 GW 1.5 GW 3.3 GW

Cape Fear 5&6 ~315 MW expected to be retired on October 1, 2012 Lee 1-3 ~390 MW potential to be retired by end of 2012 Robinson ~175 MW expected to be retired on October 1, 2012 Sutton 1-3 ~590 MW potential to be retired by end of 2013

Progress Florida ~2.3 GW

Duke Indiana ~4.8 GW

Duke Ohio ~3.5 GW

2.8 GW 1.3 GW * 0.7 GW

Crystal River 1&2 ~875 MW under evaluation for MATS compliance; potential to be retired

Duke Kentucky ~0.6 GW


DUKE ENERGY STEAM FACILITY DATA (Pro Forma as of 6/30/12)

Structure Operating State Jurisdiction Steam Unit Facility Owned Capacity –

Summer Rating (MW) Fuel Type Current Cooling Method Emissions Controls Regulated In Operation DE Carolinas Allen 1,127 Coal Once-Through Scrubber Regulated In Operation DE Carolinas Belews Creek 2,220 Coal Once-Through Scrubber and SCR Regulated In Operation (1) DE Carolinas Buck 5-6 256 Coal Once-Through Regulated In Operation DE Carolinas Cliffside 5 556 Coal Closed Cycle Scrubber and SCR Regulated In Operation (1) DE Carolinas Lee 370 Coal Once-Through

Regulated In Operation DE Carolinas Marshall 2,078 Coal Once-Through 658MW with Scrubber and SCR; 1420MW with Scrubber

Regulated In Operation (1) DE Carolinas Riverbend 4-7 454 Coal Once-Through Regulated In Operation DE Carolinas Buck CC 620 Gas Closed Cycle SCR Regulated In Operation DE Carolinas Catawba 435 Nuclear Closed Cycle Regulated In Operation DE Carolinas McGuire 2,200 Nuclear Once-Through Regulated In Operation DE Carolinas Oconee 2,538 Nuclear Once-Through Regulated In Operation PE Carolinas Asheville 376 Coal Once-Through Scrubber and SCR Regulated In Operation (1) PE Carolinas Cape Fear 316 Coal Once-Through SNCR Regulated In Operation (1) PE Carolinas Lee 391 Coal Cooling Lake Regulated In Operation PE Carolinas Mayo 609 Coal Cooling Lake Scrubber and SCR Regulated In Operation (1) PE Carolinas Robinson 1 177 Coal Once-Through Regulated In Operation PE Carolinas Roxboro 1-4 2,327 Coal Once-Through (1-3), Closed Cycle (4) Scrubber and SCR Regulated In Operation (1) PE Carolinas Sutton 1-3 590 Coal Cooling Lake SCNR on Unit 3 Regulated In Operation PE Carolinas Smith 4-5 1,122 Gas Closed Cycle SCR Regulated In Operation PE Carolinas Brunswick 1,517 Nuclear Once-Through Regulated In Operation PE Carolinas Harris 742 Nuclear Cooling Lake Regulated In Operation PE Carolinas Robinson 724 Nuclear Once-Through Regulated In Operation PE Florida Anclote 1,011 Gas/Oil Once-Through Regulated In Operation PE Florida Bartow CC 1,133 Gas Once-Through SCR Regulated In Operation (2) PE Florida Crystal River 1-2 873 Coal Once-Through Regulated In Operation PE Florida Crystal River 4-5 1,422 Coal Closed Cycle Scrubber and SCR Regulated In Operation PE Florida Hines CC 1,912 Gas Cooling Lake SCR Regulated In Operation PE Florida Suwannee River 129 Gas/Oil Once-Through Regulated In Operation PE Florida Tiger Bay 205 Gas Closed Cycle Regulated In Operation PE Florida Crystal River 3 789 Nuclear Once-Through

49

(1) Potential retirements include Buck Units 5-6; Riverbend Units 4-7; Cape Fear Units 5&6; Sutton Units 1-3; PEC Lee Units 1-3; Robinson; Wabash River Units 2-5; Miami Fort Unit 6; and Beckjord Units 1-6. Reflects already completed retirements of Edwardsport 6-8 (160 MW), Buck 3-4 (113 MW), Cliffside 1-4 (198 MW), Dan River 1-3 (276MW), Gallagher 1,3 (280MW) per Consent Decree; Weatherspoon 1-3 (177 MW); and Bartow 1-3 (440 MW). DEC Lee Units 1-3 (370MW) and Wabash River Unit 6 (320 MW) potential to be converted to gas or retired.

(2) Crystal River 1-2 875 MW under evaluation for MATS compliance; potential to be retired by 2020


DUKE ENERGY STEAM FACILITY DATA, CONT. (Pro Forma as of 6/30/12)

Structure Operating State Jurisdiction Steam Unit Facility Owned Capacity –

Summer Rating (MW) Fuel Type Current Cooling Method Emissions Controls Regulated In Operation DE Indiana Cayuga 1,005 Coal Once-Through Scrubber Regulated In Operation DE Indiana Gibson 2,822 Coal Cooling Lake, No NPDES Permit Scrubber and SCR Regulated In Operation (1) DE Indiana Wabash River 668 Coal Once-Through Regulated In Operation DE Indiana Gallagher 2&4 280 Coal Once-Through Baghouse Regulated In Operation DE Indiana Noblesville CC 310 Gas Closed Cycle Regulated In Operation DE Kentucky East Bend 414 Coal Closed Cycle Scrubber and SCR Regulated In Operation (1) DE Kentucky Miami Fort 6 163 Coal Once-Through Non-Regulated In Operation DE Ohio Conesville 4 312 Coal Closed Cycle Scrubber and SCR Non-Regulated In Operation DE Ohio Stuart 1-3 675 Coal Once-Through Scrubber and SCR Non-Regulated In Operation DE Ohio Stuart 4 225 Coal Closed Cycle Scrubber and SCR Non-Regulated In Operation DE Ohio Killen 198 Coal Closed Cycle Scrubber and SCR Non-Regulated In Operation (1) DE Ohio Beckjord 859 Coal Once-Through Non-Regulated In Operation DE Ohio Miami Fort 7-8 640 Coal Closed Cycle Scrubber and SCR Non-Regulated In Operation DE Ohio Zimmer 605 Coal Closed Cycle Scrubber and SCR Non-Regulated In Operation Duke Energy Fayette CC 633 Gas Closed Cycle SCR Non-Regulated In Operation Duke Energy Hanging Rock CC 1,262 Gas Closed Cycle SCR Non-Regulated In Operation Duke Energy Washington CC 639 Gas Closed Cycle SCR Regulated Under Construction DE Carolinas Cliffside 6 825 Coal Closed Cycle Scrubber and SCR Regulated Under Construction DE Carolinas Dan River CC 620 Gas Closed Cycle SCR Regulated Under Construction DE Indiana Edwardsport IGCC 618 Coal Closed Cycle - No Intake Selexol and SCR Regulated Under Construction PE Carolinas Wayne County CC 920 Gas Closed Cycle SCR Regulated Under Construction PE Carolinas Sutton CC 625 Gas Closed Cycle SCR

50

(1) Potential retirements include Buck Units 5-6; Riverbend Units 4-7; Cape Fear Units 5&6; Sutton Units 1-3; PEC Lee Units 1-3; Robinson; Wabash River Units 2-5; Miami Fort Unit 6; and Beckjord Units 1-6. Reflects already completed retirements of Edwardsport 6-8 (160 MW), Buck 3-4 (113 MW), Cliffside 1-4 (198 MW), Dan River 1-3 (276MW), Gallagher 1,3 (280MW) per Consent Decree; Weatherspoon 1-3 (177 MW); and Bartow 1-3 (440 MW). DEC Lee Units 1-3 (370MW) and Wabash River Unit 6 (320 MW) potential to be converted to gas or retired.

(2) Crystal River 1-2 875 MW under evaluation for MATS compliance; potential to be retired by 2020


PROGRESS ENERGY 2Q-2012 EARNINGS SUPPLEMENT


PROGRESS ENERGY 2Q-2012 EARNINGS SUMMARY

$0.37 $0.48

($0.14)

$0.71

$0.14

$0.29

($0.16)

$0.27

Carolinas Florida Consolidated

Ongoing EPS

2Q 2011 2Q 2012

Corporate & Other

GAAP Net Income & Ongoing Earnings

($ in Millions) 2Q12 2Q11 YTD 2012 YTD 2011 GAAP Net Income $ 63 $ 176 $ 213 $ 360

Adjustments* $ 17 $ 35 $ 10 $ 53

Ongoing Earnings $ 80 $ 211 $ 223 $ 413

(*) See Reg G schedules for detailed reconciliation of ongoing EPS to reported GAAP EPS


$0.71 $0.04

$0.02 $0.02 ($0.23)

($0.12)

($0.09)

($0.04)($0.02)

($0.02)$0.27

$0.00

$0.20

$0.40

$0.60

$0.80

2Q-2011Ongoing

EPS*

Clauses&

Other Margin

Growth&

Usage

Wholesale O & M Deprec.&

Amort.

Weather Other InterestExpense

Income Taxes

2Q-2012Ongoing

EPS*

EPS

(1) See Reg G schedules for reconciliation of ongoing EPS to reported GAAP EPS

D & A: ($0.02) – PEC ($0.10) – PEF primarily due to the prior year reduction in the cost of removal component of amortization expense ($0M vs. $54M prior year)

Weather: PEC: ($0.05) PEF: ($0.04)

O & M: ($0.18) – PEC primarily due to an additional

planned nuclear refueling outage ($0.05) – PEF primarily due to the non-selected

vendor for the CR3 repair option

PROGRESS ENERGY 2Q-2012 ONGOING EPS DRIVERS1

53


$1.40 $0.09

$0.04 $0.03 ($0.31)

($0.19)

($0.19)

($0.07)($0.02) ($0.02) ($0.01) $0.75

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

YTD-2011Ongoing

EPS*

Clauses&

Other Margin

Growth&

Usage

Wholesale O & M Deprec.&

Amort.

Weather Other AFUDCEquity

Income Taxes

InterestExpense

YTD-2012Ongoing

EPS*

EPS

(1) See Reg G schedules for reconciliation of ongoing EPS to reported GAAP EPS

D & A: ($0.04) – PEC ($0.15) – PEF primarily due to the smaller reduction in the cost of removal component of amortization expense ($58M vs. $134M prior year)

Weather: PEC: ($0.15) PEF: ($0.04)

O & M: ($0.34) – PEC primarily due to two additional planned

nuclear refueling outages $0.03 – PEF

PROGRESS ENERGY YTD-2012 ONGOING EPS DRIVERS1

54


1.0%

0.8%

2.2%

-0.4%

-3.0%

0.8%

-0.6%

-8.7%

-10% -8% -6% -4% -2% 0% 2%

Total Retail

Industrial

Commercial

Residential

-0.7%

-7.2%

-1.7%

1.0%

-5.4%

-7.2%

-4.3%

-6.3%

-10% -8% -6% -4% -2% 0% 2%

Total Retail

Industrial

Commercial

Residential

Actual Weather-normalized

2012 Carolinas Retail kWh Sales Growth & Usage 1.0% Weather (4.1%) Total Retail Sales (3.0%)

2012 Total Retail Sales Forecast + 1.5%

2012 Florida Retail kWh Sales Growth & Usage (0.7%) Weather (4.8%) Total Retail Sales (5.4%)

2012 Total Retail Sales Forecast (0.4%)

Progress Energy Carolinas

Note: Unbilled allocated to customer classes

PROGRESS ENERGY 2Q-2012 RETAIL VOLUMES

Progress Energy Florida

55

Second Quarter Earnings Review and Business Update August 2, 2012 56 56

Duke Energy Corporation Non-GAAP Reconciliations Second Quarter Earnings Review & Business Update August 2, 2012 Adjusted Diluted Earnings per Share (“EPS”) The materials for Duke Energy Corporation’s (“Duke Energy”) Second Quarter Earnings Review and Business Update on August 2, 2012 include a discussion of adjusted diluted EPS for the quarters and year-to-date periods ended June 30, 2012 and 2011. 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. Management believes that the presentation of adjusted diluted EPS provides useful information to investors, as it provides them an additional relevant comparison of the company’s performance across periods. Adjusted diluted EPS is also used as a basis for employee incentive bonuses. 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-to-date periods ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, to the most directly comparable GAAP measures are included here-in. 2012 Adjusted Diluted EPS Outlook The materials for Duke Energy’s Second Quarter Earnings Review and Business Update on August 2, 2012 include a discussion of the forecasted 2012 adjusted diluted EPS outlook range of $4.20 - $4.35 per share, which is consistent with the 2012 employee incentive earnings target. The materials also reference the long-term targeted range of growth of 4%-6% in adjusted diluted EPS (on a compound annual growth rate (“CAGR”) basis). 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 all special items or mark-to-market adjustments for future periods. However, Duke Energy currently expects accounting charges resulting from the merger of between $450 and $550 million to be recognized primarily in the last half of 2012. These charges, which will be treated as “special” items and will mostly affect the U.S. Franchised Electric & Gas Segment, primarily consist of employee severance costs, costs related to the interim and permanent FERC mitigation plan, concessions agreed to with the Carolinas commissions in order to receive merger approval, and merger transaction costs. Duke Energy also expects to incur significant system integration and other merger-related transition costs primarily through 2014 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger with Progress Energy. Adjusted Segment Income and Adjusted Other Net Expense for 2012 and 2011 and Forecasted Adjusted Segment Income and Adjusted Other Net Expense for 2012 The materials for Duke Energy’s Second Quarter Earnings Review and Business Update on August 2, 2012 include a discussion of adjusted segment income for the quarters and year-to-date periods ended June 30, 2012, June 30, 2011 and for the quarters ended March 31, 2012, March 31, 2011, September 30, 2011 and December 31, 2011 and a discussion of forecasted 2012 segment income. Adjusted segment income and adjusted Other net expenses are non-GAAP financial measures, as they represent reported segment income and Other net expenses adjusted for special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Management believes that the presentation of adjusted segment income 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. When an EPS amount is provided for a segment income driver, the per share impact is derived by taking the before-tax amount of the item less income taxes based on the segment’s effective tax rate, divided by the Duke Energy weighted-average shares outstanding for the period. Effective tax rates used to calculate the year-to-date per share impact on EPS are approximately 34 percent for the U.S. Franchised Electric and Gas segment, 26 percent for the International segment and 33 percent for the Commercial Power segment, excluding Renewables. Effective tax rates used to calculate the quarter per share impact on EPS are approximately 33 percent for the U.S. Franchised Electric and Gas segment, 26 percent for the International segment and 27 percent for the Commercial Power segment, excluding Renewables. The most directly comparable GAAP measure for adjusted segment income or adjusted Other net expenses is reported segment income or Other net expenses, which represents segment income and Other net expenses 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 income and Other net expenses for the quarters and year-to-date periods ended June 30, 2012 and June 30, 2011 and the quarters ended March 31, 2012, March 31, 2011, September 30, 2011 and December 31, 2011 to the most directly comparable GAAP measures are included below. Due to the forward-looking nature of any forecasted adjusted segment income or adjusted Other net expenses and any related growth rates for future periods, information to reconcile these non-GAAP financial measures to the most directly comparable GAAP financial measures is not available at this time, as the company is unable to forecast special items, the mark-to-market impacts of economic hedges in the Commercial Power segment, or any amounts that may be reported as discontinued operations or extraordinary items for future periods. However, Duke Energy currently expects accounting charges resulting from the merger of between $450 and $550 million to be recognized primarily in the last half of 2012. These charges, which will be treated as “special” items and will mostly affect the U.S. Franchised Electric & Gas Segment, primarily consist of employee severance costs, costs related to the interim and permanent FERC mitigation plan, concessions agreed to with the Carolinas commissions in order to receive merger approval,

and merger transaction costs. Duke Energy also expects to incur significant system integration and other merger-related transition costs primarily through 2014 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger with Progress Energy. Adjusted Effective Tax Rate The materials for Duke Energy’s Second Quarter Earnings Review and Business Update on August 2, 2012 include a discussion of the adjusted effective tax rate (“ETR”) for the year-to-date period ended June 30, 2012. Adjusted effective tax rate is a non-GAAP financial measure as the rate is calculated using a pre-tax earnings and income tax expense, both adjusted for the impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. The most directly comparable GAAP measure for adjusted effective tax rate is reported effective tax rate, which includes the impact of special items and the mark-to-market impacts of economic hedges in the Commercial Power segment. Reconciliation of the adjusted effective tax rate for the year-to-date period ended June 30, 2012 to the most directly comparable GAAP measure is included below (amounts in millions). Adjusted Earnings, Pre-Tax Income $1,404 Edwardsport Impairment (420) Voluntary Severance Opportunity Plan Deferral 99 Costs-to-Achieve Progress Energy Merger (15) Economic Hedges (Mark-to-Market) (4) Discontinued Operations (1) Reported Income Before Income Taxes from Continuing Operations $1,063 Adjusted Tax Expense $433 Adjusted ETR 30.8% Edwardsport Impairment (152) Voluntary Severance Opportunity Plan Deferral 39 Costs-to-Achieve Progress Energy Merger (2) Economic Hedges (Mark-to-Market) (1) Reported Income Tax Expense from Continuing Operations $317 Reported ETR 29.8% Dividend Payout Ratio The materials for Duke Energy’s Second Quarter Earnings Review and Business Update on August 2, 2012 include a discussion of Duke Energy’s anticipated long-term dividend payout ratio of 65-70% based upon adjusted diluted EPS. This payout ratio is a non-GAAP financial measure as it is based upon forecasted 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, as discussed above 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.

Duke Energy Corporation2012 Forecasted Cash Flow Reconciliation, Required by SEC Regulation G Second Quarter 2012 Earnings Review and Business UpdateAugust 2, 2012($ in millions)

Forecast2012

Primary Sources:Adjusted net income (1) (a) 2,450$ Depreciation & amortization (a) 2,660 Deferred and accrued taxes (a) 1,130 Other sources / (uses), net (a) (1,445)

Total Sources 4,795

Primary Uses:Capital and investment expenditures (b) (5,600) Dividends (c) (1,745) Pension plan contributions (a) (285)

Total Uses (7,630)

Uses in Excess of Sources (2,835) Debt maturities (c) (2,810)

Required Funding (5,645) Debt issuances (c),(d) 4,880 Equity issued from internal plans (c) - Utilization of cash (e) 765

Total Financings and Cash Utilization 5,645$

Reconciliations to forecasted U.S. GAAP reporting amounts:Operating cash flow components, sum of (a) from above 4,510$ Reconciling items to GAAP cash flows from operating activities (2),(3) (135) Net cash provided by operating activities per GAAP Consolidated Statement of Cash Flows 4,375$

Investing cash flow components, (b) from above (5,600)$ Reconciling items to GAAP cash flows from investing activities (2) 160 Net cash used in investing activities per GAAP Consolidated Statement of Cash Flows (5,440)$

Financing cash flow components, sum of (c) from above 325$ Reconciling items to GAAP cash flows from financing activities (3) (25) Net cash provided by financing activities per GAAP Consolidated Statement of Cash Flows 300$ Net cash provided by financing activities per GAAP Consolidated Statement of Cash Flows 300$

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

Utilization of cash [(e) from above] is the equivalent of Net decrease in cash and cash equivalents per forecasted GAAP Consolidated Statements of Cash Flows (765)$

Notes:

(1) The forecasted adjusted net income of $2,450 million for 2012 is an illustrative amount based on an amount within the range of Duke Energy's adjusted diluted EPS outlook range of $4.20-$4.35 per share. 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 all special items or mark-to-market adjustments for future periods. However, Duke Energy currently expects accounting charges resulting from the merger of between $450 and $550 million , some of which are non-cash items, to be recognized primarily in the last half of 2012. These charges, which will be treated as “special” items and will mostly affect the U.S. Franchised Electric & Gas Segment, primarily consist of employee severance costs, costs related to the interim and permanent FERC mitigation plan, concessions agreed to with the Carolinas commissions in order to receive merger approval, and merger transaction costs. Duke Energy also expects to incur significant system integration and other merger-related transition costs primarily through 2014 that are necessary in order to achieve certain cost savings, efficiencies and other benefits anticipated to result from the merger with Progress Energy.

(2) Amount consists primarily of an adjustment for investing cash flow items (principally sales of equity method investments and other assets) included in the "Other sources/(uses), net", which are combined for the GAAP reconciliation in Operating activities.

(3) Amount consists primarily of net other financing activities, including distributions to noncontrolling interests, included in the "Other sources/(uses), net", which are combined for the GAAP reconciliation in Operating activities.

Special Items (Note 1)

Adjusted Earnings

Costs to Achieve, Progress Merger

Economic Hedges (Mark-to-Market) *

Discontinued Operations

Total Adjustments

Reported Earnings

SEGMENT NET INCOME FROM CONTINUING OPERATIONS ATTRIBUTABLE TO DUKE ENERGY CORPORATION

U.S. Franchised Electric and Gas 337$ -$ -$ -$ -$ 337$

Commercial Power 32 - (4) B - (4) 28

International Energy 105 - - - - 105

Total Reportable Segment Income 474 - (4) - (4) 470

Other (18) (7) A - - (7) (25)

Total Reportable Segment Income and Other Net E xpense 456$ (7)$ (4)$ -$ (11)$ 445

Discontined Operations - (1) C (1) (1)

Net Income (Loss) Attributable to Duke Energy Corporation 456$ (7)$ (4)$ (1)$ (12)$ 444$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC 1.02$ (0.02)$ $ (0.01) -$ (0.03)$ 0.99$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED 1.02$ (0.02)$ $ (0.01) -$ (0.03)$ 0.99$

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

Weighted Average Shares (reported and adjusted) - i n millions

Basic 446

Diluted 446

C - Recorded in Income (Loss) From Discontinued Ope rations, net of tax on the Condensed Consolidated S tatements of Operations.

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify f or hedge or regulatory accounting, used in Duke Ene rgy Corporation’s hedging of a portion of the economic value of its generation assets in the Commercial Po wer segment. The economic value of the generation a ssets is subject to fluctuations in fair value due to market price volatility of the input and output com modities (e.g. coal, gas, power) and, as such, the economic hedging involves both purchases and sales of those input and output commodities related to th e generation assets. Because the operations of the ge neration assets are accounted for under the accrual method, management believes that excluding the imp act of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement b etter matches the financial impacts of the hedge co ntract with the portion of the economic value of th e underlying hedged asset. Management believes that the presentation of adjusted diluted EPS Attributable t o Duke Energy Corporation provides useful informati on to investors, as it provides them an additional relevant comparison of Duke Energy Corporation's performance across periods.

DUKE ENERGY CORPORATIONADJUSTED TO REPORTED EARNINGS RECONCILIATION

Three Months Ended June 30, 2012(Dollars in millions, except per-share amounts)

A - Net of insignificant tax benefit. Recorded in O peration, maintenance and other (Operating Expenses ) on the Condensed Consolidated Statements of Opera tions.

B - Net of $2 million tax benefit. Recorded within Non-regulated electric, natural gas, and other (Ope rating Revenues) on the Condensed Consolidated Stat ements of Operations.

Adjusted Earnings


Voluntary Opportunity Plan Deferral

Edwardsport Impairment

Economic Hedges (Mark-

to-Market) *Discontinued Operations

Total Adjustments

Reported Earnings

SEGMENT INCOME

U.S. Franchised Electric and Gas 681$ -$ 60$ C (268)$ E -$ -$ (208)$ 473$

Commercial Power 62 - - - (3) B - (3) 59

International Energy 247 - - - - - - 247

Total Reportable Segment Income 990 - 60 (268) (3) - (211) 779

Other (28) (13) A - - - - (13) (41)

Total Reportable Segment Income and Other Net E xpense 962 (13) 60 (268) (3) - (224) 738

Discontinued Operations - - - - - 1 D 1 1

Net Income (Loss) Attributable to Duke Energy Corporation 962$ (13)$ 60$ (268)$ (3)$ 1$ (223)$ 739$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC 2.16$ (0.03)$ 0.13$ $ (0.60) $ (0.01) -$ (0.51)$ 1.65$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED 2.16$ (0.03)$ 0.13$ $ (0.60) $ (0.01) -$ (0.51)$ 1.65$


Basic 446

Diluted 446

E - Net of $152 million tax benefit. $400 million r ecorded in Impairment charges and $20 million recor ded within within Operation, maintenance and other (all Operating Expenses) on the Condensed Consolidated Statements of Operations.

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify f or hedge or regulatory accounting, used in Duke Ene rgy Corporation’s hedging of a portion of the econo mic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subj ect to fluctuations in fair value due to market pri ce volatility of the input and output commodities ( e.g. coal, gas, power) and, as such, the economic h edging involves both purchases and sales of those input and output commodities related to the generation assets. Becau se the operations of the generation assets are acco unted for under the accrual method, management beli eves that excluding the impact of mark-to-market ch anges of the economic hedge contracts from adjusted earnings until settlement better matches the financial impa cts of the hedge contract with the portion of the e conomic value of the underlying hedged asset. Manag ement believes that the presentation of adjusted di luted EPS Attributable to Duke Energy Corporation provides us eful information to investors, as it provides them an additional relevant comparison of Duke Energy Co rporation's performance across periods.

A - Net of $2 million tax benefit. Recorded in Oper ation, maintenance and other (Operating Expenses) o n the Condensed Consolidated Statements of Operatio ns.

B - Net of $1 million tax benefit. $3 million loss recorded within Non-regulated electric, natural gas , and other (Operating Revenues) and $1 million los s recorded within Fuel used in electric generation and purchased power- non-regulated (Operating Expenses) on the Cond ensed Consolidated Statements of Operations.

C - Net of $39 million tax expense. $101 million re venue recorded in Operation, maintenance and other and $2 million expense recorded in Depreciation and amortization (all Operating Expenses) on the Condensed Consolidated Statements of Operations.

D - Recorded in Income (Loss) From Discontinued Ope rations, net of tax on the Condensed Consolidated S tatements of Operations.


Six Months Ended June 30, 2012(Dollars in millions, except per-share amounts)

Special Items

Special Items

Adjusted Earnings


Reported Earnings

SEGMENT INCOME

U.S. Franchised Electric and Gas 297$ -$ 297$

Commercial Power 30 - 30

International Energy 127 - 127

Total reportable segment income 454 - 454

Other (15) (4) A (19)

$ 439 $ (4) $ 435

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 0.99 $ (0.01) $ 0.98

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 0.99 $ (0.01) 0.98$

Statements of Operations.


Basic 444

Diluted 444

Net Income (Loss) Attributable to Duke Energy Corporation

A - Net of $1 million tax benefit. Recorded in Oper ation, maintenance and other (Operating Expenses) o n the Condensed Consolidated

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify for hedge or regulatory accounting, used in Duke Energy Corporation’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 fluctuation s in fair value due to market price volatility of the input and output commodities (e.g. coal, gas , power) and, as such, the economic hedging involve s both purchases and sales of those input and output commodities related to the generation as sets. Because the operations of the generation asse ts are accounted for under the accrual method, management believes that excluding the impa ct 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 adjust ed diluted EPS Attributable to Duke Energy Corporat ion provides useful information to investors, as it provides them an additional releva nt comparison of Duke Energy Corporation's performa nce across periods.


Three Months Ended June 30, 2011(Dollars in millions, except per-share amounts)

Special Items

Adjusted Earnings



to-Market) *Total

AdjustmentsReported Earnings

SEGMENT INCOME

U.S. Franchised Electric and Gas 638$ -$ -$ -$ 638$

Commercial Power 82 - (3) B (3) 79

International Energy 255 - - - 255

Total Reportable Segment Income 975 - (3) (3) 972

Other (13) (13) A - (13) (26)

$ 962 $ (13) $ (3) $ (16) $ 946

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 2.17 $ (0.03) $ (0.01) $ (0.04) 2.13$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 2.17 $ (0.03) $ (0.01) $ (0.04) 2.13$

A - Net of $3 million tax benefit. Recorded in Oper ation, maintenance and other (all Operating Expense s) on the Condensed Consolidated Statements of Oper ations.


Basic 444

Diluted 444


B - Net of $1 million tax benefit. $2 million loss recorded within Non-regulated electric, natural ga s, and other (Operating Revenues) and $2 million lo ss recorded within Fuel used in electric generation and purchased power-non-regulated (Opera ting Expenses) on the Condensed Consolidated Statem ents of Operations.

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify f or hedge or regulatory accounting, used in Duke Energy Corporation’s hedging of a port ion 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 commoditi es (e.g. coal, gas, power) and, as such, the econom ic hedging involves both purchases and sales of those input and output commodities related to the generation assets. Because the operations o f the generation assets are accounted for under the accrual method, management believes that excluding the impact of mark-to-marke t changes of the economic hedge contracts from adju sted earnings until settlement better matches the f inancial impacts of the hedge contract with the portion of the economic value of the underlying hedged asset. Management believes th at the presentation of adjusted diluted EPS Attribu table to Duke Energy Corporation provides useful information to investors, as it pro vides them an additional relevant comparison of Duk e Energy Corporation's performance across periods.


Six Months Ended June 30, 2011(Dollars in millions, except per-share amounts)

Adjusted Earnings


Voluntary Opportunity Plan Deferral




Total Adjustments

Reported Earnings

SEGMENT INCOME

U.S. Franchised Electric and Gas 344$ -$ 60$ C (268)$ E -$ -$ (208)$ 136$

Commercial Power 30 - - 1 B - 1 31


Total reportable segment income 516 - 60 (268) 1 - (207) 309

Other (10) (6) A - - (6) (16)

Total Reportable Segment Income and Other Net E xpense 506 (6) 60 (268) 1 - (213) 293


Net Income (Loss) Attributable to Duke Energy Corporation 506$ (6)$ 60$ (268)$ 1$ 2$ (211)$ 295$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC 1.13$ (0.01)$ 0.13$ $ (0.60) $ - 0.01$ (0.47)$ 0.66$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED 1.13$ (0.01)$ 0.13$ $ (0.60) $ - 0.01$ (0.47)$ 0.66$


Basic 446

Diluted 446


Three Months Ended March 31, 2012(Dollars in millions, except per-share amounts)

Special Items

E - Net of $152 million tax benefit. $400 million r ecorded in Goodwill and other impairment charges an d $20 million recorded within within Operation, mai ntenance and other (all Operating Expenses) on the Condensed Consolidated Statements of Operations.

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify f or hedge or regulatory accounting, used in Duke Ene rgy Corporation’s hedging of a portion of the econo mic value of its generation assets in the Commercial Power segme nt. The economic value of the generation assets is subject to fluctuations in fair value due to market price volatility of the input and output commoditi es (e.g. coal, gas, power) and, as such, the econom ic hedging involves both purchases and sales of those input an d output commodities related to the generation asse ts. Because the operations of the generation assets are accounted for under the accrual method, manage ment believes that excluding the impact of mark-to- market changes of the economic hedge contracts from adjust ed earnings until settlement better matches the fin ancial impacts of the hedge contract with the porti on of the economic value of the underlying hedged a sset. Management believes that the presentation of adjusted diluted EPS Attributable to Duke Energy Corporation provides useful information to investors, as it pr ovides them an additional relevant comparison of Du ke Energy Corporation's performance across periods.


B - Net of $1 million tax expense. $3 million gain recorded within Non-regulated electric, natural gas , and other (Operating Revenues) and $1 million los s recorded within Fuel used in electric generation and purchased power- non-regulated (Operating Expenses) on the Cond ensed Consolidated Statements of Operations.

C - Net of $39 million tax expense. $101 million re venue recorded in Operation, maintenance and other and $2 million expense recorded in Depreciation and amortization (all Operating Expenses) on the Condensed Consolidated Statements of Operations.

D - Recorded in Income (Loss) From Discontinued Ope rations, net of tax on the Condensed Consolidated S tatements of Operations.

Special Items

Adjusted Earnings



to-Market) *Total


SEGMENT INCOME

U.S. Franchised Electric and Gas 341$ -$ -$ -$ 341$

Commercial Power 52 - (3) B (3) 49

International Energy 128 - - - 128

Total reportable segment income 521 - (3) (3) 518

Other - (7) A - (7) (7)

$ 521 $ (7) $ (3) $ (10) $ 511

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 1.18 $ (0.02) $ (0.01) $ (0.03) 1.15$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 1.17 $ (0.02) $ - $ (0.02) 1.15$

A - Net of $4 million tax benefit. Recorded in Oper ation, maintenance and other (all Operating Expense s) on the Condensed Consolidated Statements of Oper ations.


Basic 443

Diluted 444


B - Net of $1 million tax benefit. $2 million loss recorded within Non-regulated electric, natural ga s, and other (Operating Revenues) and $2 million lo ss recorded within Fuel used in electric generation and purchased power-non-regulated (Opera ting Expenses) on the Condensed Consolidated Statem ents of Operations.



Three Months Ended March 31, 2011(Dollars in millions, except per-share amounts)

Adjusted Earnings



Emission Allowances Impairment



Total Adjustments

Reported Earnings

SEGMENT INCOME

U.S. Franchised Electric and Gas 472$ -$ (135)$ E - - -$ (135)$ 337$

Commercial Power 73 - - (51) C 1 B - (50) 23


Total reportable segment income 660 - (135) (51) 1 - (185) 475

Other 6 (10) A - - - - (10) (4)

Total Reportable Segment Income and Other Net E xpense 666 (10) (135) (51) 1 - (195) 471


$ 666 $ (10) $ (135) $ (51) $ 1 1$ $ (194) $ 472

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 1.50 $ (0.02) $ (0.30) $ (0.12) $ - $ - $ (0.44) $ 1.06

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 1.50 $ (0.02) $ (0.30) $ (0.12) $ - $ - $ (0.44) 1.06$

B - Net of insignificant tax benefit. $2 million ga in recorded within Non-regulated electric, natural gas, and other (Operating Revenues) and $1 million loss recorded within Fuel used in electric generati on and purchased power-non-regulated

D- Recorded in Income (Loss) From Discontinued Oper ations, net of tax on the Condensed Consolidated St atements of Operations.


Basic 444

Diluted 444


Three Months Ended September 30, 2011(Dollars in millions, except per-share amounts)

Special Items

E - Net of $87 million tax benefit. Recorded in Goo dwill and other impairment charges within Operating Expenses on the Condensed Consolidated Statements of Operations.

* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedi ately as such derivative contracts do not qualify f or hedge or regulatory accounting, used in Duke Ene rgy Corporation’s hedging of a portion of the economic value of its generation assets in the Comm ercial Power segment. The economic value of the gen eration assets is subject to fluctuations in fair v alue due to market price volatility of the input an d output commodities (e.g. coal, gas, power) and, as such, the economic hedging involves both pu rchases and sales of those input and output commodi ties related to the generation assets. Because the operations of the generation assets are accounted f or under the accrual method, management believes that excluding the impact of ma rk-to-market changes of the economic hedge contract s from adjusted earnings until settlement better ma tches the financial impacts of the hedge contract w ith the portion of the economic value of the underlying hedged asset. Management believes th at the presentation of adjusted diluted EPS Attribu table to Duke Energy Corporation provides useful in formation to investors, as it provides them an addi tional relevant comparison of Duke Energy Corporation's performance across periods.



(Operating Expenses) on the Condensed Consolidated Statements of Operations.

C - Net of $28 million tax benefit. Recorded in Goo dwill and other impairment charges within Operating Expenses on the Condensed Consolidated Statements of Operations.

Special Items

Adjusted Earnings



to-Market) *Total


SEGMENT INCOME

U.S. Franchised Electric and Gas 206$ -$ -$ 206$

Commercial Power 30 - 1 B 1 31

International Energy 96 - - 96

Total reportable segment income 332 - 1 1 333

Other (17) (28) A (28) (45)

$ 315 $ (28) $ 1 $ (27) $ 288

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 0.71 $ (0.06) $ - $ (0.06) $ 0.65

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 0.71 $ (0.06) $ - $ (0.06) 0.65$

B - Net of $1 million tax expense. Recorded within Non-regulated electric, natural gas, and other (Ope rating Revenues) on the Consolidated Statements of Operations.


Basic 445

Diluted 445


Three Months Ended December 31, 2011(Dollars in millions, except per-share amounts)


A - Net of $11 million tax benefit. Recorded in Ope ration, maintenance and other (Operating Expenses) on the Consolidated Statements of Operations.

on the Condensed Consolidated Statements of Operati ons.


Adjusted Earnings



Emission Allowances Impairment



Total Adjustments

Reported Earnings

Net Income (Loss) Attributable to Duke Energy Corporation 1,943$ (51)$ (135)$ (51)$ (1)$ 1$ (237)$ 1,706$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC 4.38$ (0.12)$ (0.30)$ $ (0.12) $ - -$ (0.54)$ 3.84$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED 4.38$ (0.12)$ (0.30)$ $ (0.12) $ - -$ (0.54)$ 3.84$

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

Weighted Average Shares (reported and adjusted) - in mill ionsBasic 444

Diluted 444

* Represents the mark-to-market impact of derivative contracts , which is recognized in earnings immediately as suc h derivative contracts do not qualify for hedge or regula tory accounting, used in Duke Energy Corporation’s hed ging of a portion of the economic value of its generation assets in the Commercial Power s egment. The economic value of the generation assets is s ubject to fluctuations in fair value due to market price vo latility of the input and output commodities (e.g. coal, gas , power) and, as such, the economic hedging involves both purchases and sales of those inp ut and output commodities related to the generation assets. Because the operations of the generation assets are accou nted for under the accrual method, management believes th at excluding the impact of mark-to-market changes of the economic hedge contracts from adjusted earnings until settlement better matches the financi al impacts of the hedge contract with the portion of the econ omic value of the underlying hedged asset. Management b elieves that the presentation of adjusted diluted EPS Attributable to Duke En ergy Corporation provides useful information to investors , as it provides them an additional relevant comparison of Duke Energy Corporation's performance across perio ds.


Twelve Months Ended December 31, 2011(Dollars in millions, except per-share amounts)


Adjusted Earnings

Costs to Achieve, Cinergy Merger

Voluntary Opportunity Plan/ Office

Consolidation Costs

Goodwill and Other

ImpairmentsLitigation Reserve Asset Sales



Total Adjustments

Reported Earnings

1,882$ (17)$ (105)$ (602)$ (16)$ 154$ 21$ 3$ (562)$ 1,320$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, BASIC $ 4.29 $ (0.04) $ (0.24) $ (1.37) $ (0.04) $ 0.35 $ 0.05 $ - $ (1.29) 3.00$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED $ 4.28 $ (0.04) $ (0.24) $ (1.37) $ (0.04) $ 0.35 $ 0.05 $ 0.01 $ (1.28) 3.00$

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


Basic 439

Diluted 440


* Represents the mark-to-market impact of derivativ e contracts, which is recognized in earnings immedia tely as such derivative contracts do not qualify fo r hedge or regulatory accounting, used in Duke Ener gy Corporation’s hedging of a portion of the econom ic value of its generation assets in the Commercial Power segment. The economic value of the generation assets is subject to fluctuation s in fair value due to market price volatility of t he input and output commodities (e.g. coal, gas, po wer) and, as such, the economic hedging involves bo th purchases and sales of those input and output commodities related to the generat ion assets. Because the operations of the generatio n assets are accounted for under the accrual method , management believes that excluding the impact of mark-to-market changes of the economic hedge contra cts from adjusted earnings until settlement better matches the financial impac ts of the hedge contract with the portion of the ec onomic value of the underlying hedged asset. Manage ment believes that the presentation of adjusted dil uted EPS Attributable to Duke Energy Corporation pr ovides useful information to investors, as it provides them an additional releva nt comparison of Duke Energy Corporation's performan ce across periods.




Adjusted Earnings

Costs to Achieve, Cinergy Merger

Crescent Related Guarantees and Tax Adjustments

International Transmission Adjustment

Goodwill and Other

Impairments

Economic Hedges

(Mark-to-Market) *


Total Adjustments

Reported Earnings

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 3.66$ (0.03)$ (0.07)$ $ (0.05) $ (0.95) $ (0.09) 0.02$ (1.17)$ 2.49$

EPS ATTRIBUTABLE TO DUKE ENERGY CORPORATION, DILUTED 3.66$ (0.03)$ (0.07)$ $ (0.05) $ (0.95) $ (0.09) 0.02$ (1.17)$ 2.49$

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

Weighted Average Shares (reported and adjusted) - in mill ions

Basic 431

Diluted 431

* Represents the mark-to-market impact of derivative contracts , which is recognized in earnings immediately as suc h derivative contracts do not qualify for hedge or regula tory accounting, used in Duke Energy Corporation’s hed ging of a portion of the economic value of its generation assets in the Commercial Power segment. The economic v alue 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, gas, power) and, as such, the economic hedging involves both purchases and sal es of those input and output commodities related to the generati on 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 financi al impacts of the hedge contract with the portion of the econ omic value of the underlying hedged asset. Management b elieves that the presentation of adjusted diluted EPS Attribu table to Duke Energy Corporation provides useful information to investors, as it provides them an ad ditional relevant comparison of Duke Energy Corporation 's performance across periods.




Cash and Cash Equivalents (a) $1,526

Short-Term Investments 234

Subtotal 1,760

Less: Amounts Held in Foreign Jurisdictions (1,338)

$422

Plus: Remaining Availability under Master Credit and Regional Bank Credit Facilities 2,804

Total Available Liquidity as of June 30, 2012 (a) $3,226 (approximately $3.2 billion)

Add: Progress Energy cash and cash equivalents as of June 30, 2012 73

Add: Available Capacity added as a result of Progress Energy merger, effective July 3, 2012 1,617

Total Available Liquidity as of July 3, 2012 (a) $4,916 (approximately $4.9 billion)

(a)

Duke Energy CorporationAvailable Liquidity Reconciliation

As of June 30, 2012(In millions)

The available liquidity balance presented is a non-GAAP financial measure as it represents cash and cash equivalents (excluding amounts held in foreign jurisdictions) and remaining availability under the master credit and regional bank credit facilities. The most directly comparable GAAP financial measure for available liquidity is cash and cash equivalents.

Progress Energy, Inc. Non-GAAP Reconciliations Second Quarter Earnings Review & Business Update August 2, 2012

ONGOING EARNINGS ADJUSTMENTS

For periods ended on or before June 30, 2012, Progress Energy’s management used ongoing earnings per share to evaluate the operations of the company and to establish goals for management and employees. Management believed this non-GAAP measure was appropriate for understanding the business and assessing potential future performance, because excluded items were limited to those that management believed were not representative of fundamental core earnings. Ongoing earnings as presented here may not be comparable to similarly titled measures used by other companies. Ongoing earnings was computed as GAAP net income attributable to controlling interests (or GAAP earnings) less discontinued operations and the effects of certain identified gains and charges. The following table provides a reconciliation of ongoing earnings per share to reported GAAP earnings per share.

Progress Energy, Inc. Reconciliation of Ongoing Earnings per Share to Reported GAAP Earnings per Share

Three months ended June 30 Six months ended June 30

2012 2011 2012 2011 Ongoing earnings per share $0.27 $0.71 $0.75 $1.40 Tax levelization (0.02) (0.01) (0.04) (0.02) Discontinued operations (0.02) - 0.02 (0.01) CR3 indemnification adjustment (charge) 0.02 (0.09) 0.02 (0.09) Merger and integration costs (0.04) (0.02) (0.06) (0.07) CVO mark-to-market - 0.01 0.03 0.01 Reported GAAP earnings per share $0.21 $0.60 $0.72 $1.22 Shares outstanding (millions) 297

296 297 295

Reconciling adjustments from ongoing earnings to GAAP earnings are as follows:

Tax Levelization

Generally accepted accounting principles require companies to apply an effective tax rate to interim periods that is consistent with a company’s estimated annual tax rate. The company projects the effective tax rate for the year and then, based upon projected operating income for each quarter, increases or decreases the tax expense recorded in that quarter to reflect the projected tax rate. Because this adjustment varies by quarter but has no impact on annual earnings, management did not consider this item to be representative of the company’s fundamental core earnings.


Discontinued operations include amounts related to adjustments of prior sales of diversified businesses. In 2012, the company recorded the reversal of certain environmental indemnification liabilities for which the indemnification period has expired. Resolution of guarantees and indemnifications providing for certain legal, tax and environmental matters could result in additional adjustments. Management did not consider this item to be representative of the company’s fundamental core earnings.

CR3 Indemnification Adjustment (Charge)

The company recorded a CR3 indemnification charge, and subsequent adjustment, for estimated future years’ joint owner replacement power costs (through the expiration of the indemnification provisions of the joint owner agreement). Since GAAP requires that the charge be accounted for in the period in which it becomes probable and estimable rather than the periods to which it relates, management did not consider this item to be representative of the company’s fundamental core earnings.

Merger and Integration Costs

The company recorded charges for merger and integration costs related to the merger. Management did not consider this item to be representative of the company’s fundamental core earnings.

Contingent Value Obligations (CVO) Mark-to-Market

In connection with the acquisition of Florida Progress Corporation, Progress Energy issued CVOs that represent the right of the holder to receive contingent payments based on net after-tax cash flows above certain levels of four synthetic fuels facilities purchased by subsidiaries of Florida Progress Corporation in October 1999. The CVO liability is valued at fair value, and gains and losses from changes in fair value of CVOs not held by Progress Energy are recognized in earnings. Progress Energy is unable to predict the changes in the fair value of the CVOs, and management did not consider this item to be representative of the company’s fundamental core earnings.

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