4th Quarter 2011 Earnings & 2012 Guidance Call February 16, 2012

Bill Johnson Chairman, President & CEO 4th Quarter 2011 Earnings & 2012 Guidance Call February 16, 2012 Mark Mulhern Chief Financial Officer

Caution Regarding Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed in this document involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: our ability to obtain the approvals required to complete the Merger and the impact of compliance with material restrictions or conditions potentially imposed by our regulators; the risk that the Merger is terminated prior to completion and results in significant transaction costs to us; our ability to achieve the anticipated results and benefits of the Merger; the impact of business uncertainties and contractual restrictions while the Merger is pending; the scope of necessary repairs of the delamination of CR3 could prove more extensive than is currently identified, such repairs could prove not to be feasible, the costs of repair and/or replacement power could exceed our estimates and insurance coverage or may not be recoverable through the regulatory process; the impact of fluid and complex laws and regulations, including those relating to the environment and energy policy; our ability to recover eligible costs and earn an adequate return on investment through the regulatory process; the ability to successfully operate electric generating facilities and deliver electricity to customers; the impact on our facilities and businesses from a terrorist attack, cyber security threats and other catastrophic events; the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our regulated service territories and the accompanying regulatory and financial risks; our ability to meet current and future renewable energy requirements; the inherent risks associated with the operation and potential construction of nuclear facilities, including environmental, health, safety, regulatory and financial risks; the financial resources and capital needed to comply with environmental laws and regulations; risks associated with climate change; weather and drought conditions that directly influence the production, delivery and demand for electricity; recurring seasonal fluctuations in demand for electricity; the ability to recover in a timely manner, if at all, costs associated with future significant weather events through the regulatory process; fluctuations in the price of energy commodities and purchased power and our ability to recover such costs through the regulatory process; our ability to control costs, including operations and maintenance expense (O&M) and large construction projects; the ability of our subsidiaries to pay upstream dividends or distributions to Progress Energy, Inc. holding company; current economic conditions; the ability to successfully access capital markets on favorable terms; the stability of commercial credit markets and our access to short- and long-term credit; the impact that increases in leverage or reductions in cash flow may have on us; our ability to maintain our current credit ratings and the impacts in the event our credit ratings are downgraded; the investment performance of our nuclear decommissioning trust (NDT) funds; the investment performance of the assets of our pension and benefit plans and resulting impact on future funding requirements; the impact of potential goodwill impairments; our ability to fully utilize tax credits generated from the previous production and sale of qualifying synthetic fuels under Internal Revenue Code Section 29/45K; and the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements. Many of these risks similarly impact our nonreporting subsidiaries. These and other risk factors are detailed from time to time in our filings with the SEC. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can management assess the effect of each such factor on us. Any forward-looking statement is based on information current as of the date of this presentation and speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

CEO Topics Ongoing earnings highlights Status of merger approvals Florida settlement and Crystal River 3 update 2012 key focus areas 3

Ongoing Earnings ($M) Ongoing Earnings ($M) 2011 Ongoing Earnings Highlights* (Unaudited) $150 $133 4 th Quarter $0.45 $0.50 $900 $800 Full Year $889 $3.06 $871 $2.95 $3.00 $100 $50 $114 $0.39 $0.40 $0.30 $0.20 Ongoing EPS $700 $600 $500 $400 $300 $2.50 $2.00 $1.50 $1.00 Ongoing EPS $0.10 $200 $100 $0.50 $0 Earnings 4Q-10 4Q-11 EPS $0.00 $0 Earnings YTD-10 EPS YTD-11 $0.00 Announcing 2012 ongoing EPS guidance of $3.10 - $3.25 *See appendix for reconciliation of ongoing EPS to reported GAAP EPS. 4

Status of Merger Filings (as of February 16, 2012) Stakeholder Progress on Key Milestones Filed Approved Shareholder Department of Justice (DOJ) Federal Communications Commission (FCC) Federal Energy Regulatory Commission (FERC) Nuclear Regulatory Commission (NRC) North Carolina Received shareholder approvals on August 23, 2011 R To date, the parties have met their obligations under the Hart-Scott-Rodino Act (HSR) The period for closing consistent with the HSR Act initial filings expires April 26, 2012 As merger close will not occur prior to that date, the parties intend to make new HSR Act filings prior to April 26 expiration R R Waiting period expired Received approval of Assignment of Authorization filings on July 27, 2011 On January 5, 2012, approval extended by FCC through July 12, 2012 R R Made three merger related filings on April 4, 2011: merger application, joint dispatch agreement (JDA) Merger and joint open access transmission tariff (OATT) R c Received conditional merger approval on September 30, 2011 Filed proposed market power mitigation plan on October 17, 2011 JDA R c Proposed market power mitigation plan rejected December 14, 2011 Working toward filing revised market power mitigation plan in Q1 2012 OATT R c Received approval of indirect transfer of Progress Energy licenses on December 2, 2011 R R Filed merger approval application on April 4, 2011 NC Public Staff filed settlement agreement on September 2, 2011; companies signed settlement with SC ORS, a party to the NC docket, on September 6, 2011 Hearings held September 20-22, 2011 Proposed orders and briefs filed with NCUC on November 23, 2011 R c South Carolina Kentucky Submitted merger-related filings on April 25, 2011 Hearing to approve joint dispatch agreement held December 12, 2011 Proposed orders and briefs filed with SC PSC on December 20, 2011 R c Received Kentucky Commission approval on October 28, 2011 R R 5

Florida Settlement Agreement and Crystal River 3 Update Crystal River Unit 3 (CR3) Retains flexibility on decision to repair or retire unit Resolves prudence issues from steam generator replacement project inception through the date Commission approves settlement Resolves CR3 replacement fuel and purchased power issues/costs from 2009 to 2016 Allocates risk on repair costs based on timing of NEIL coverage resolution and Company s decision to repair or retire Levy Nuclear Project Preserves potential future benefits of new nuclear generation in Florida Uncollected balance (~ $350 million projected at year-end 2012) to be recovered in the nuclear cost recovery clause over five years (2013-2017) Full recovery of all retail project costs if the Company ultimately chooses to cancel the contract Current wholesale portion (~ $100 million) to be amortized by 2016 as a retail regulatory asset Base Rate Case (2013 2016) Revenue requirement increase ($150 million) Refund $288M to customers through the fuel clause (corresponding charge recorded in 2011) ROE @ 10.5% plus or minus 100 basis points (increase to 10.7% upon CR3 return to service) CR3 removed from rate base, effective 2013; will accrue a return, with automatic revenue increase, when returned to service Retains cost of removal flexibility throughout term 6

2012 Key Focus Areas Improve nuclear fleet performance Accelerate Continuous Business Excellence Optimize Balanced Solution Strategy Achieve effective integration planning and merger approvals In addition, maintain strong focus on the daily fundamentals of safety, operations and customer satisfaction 7

CFO Topics 2011 financial highlights and ongoing earnings review 2012 earnings guidance Earnings drivers Capital expenditures Cash flow Financing plan 8

2011 Financial Highlights Delivered ongoing earnings of $2.95 per share, which included a negative $0.08 charge for the impact of replacement power disallowances in the Carolinas Filed comprehensive settlement in Florida which will provide additional regulatory certainty through 2016 Preserved flexibility for 2012 and beyond with cost of removal amortization at PEF Achieved 2011 total shareholder return of 36.4% 9

2011 Ongoing EPS* (Unaudited) 4 th Quarter Full Year $0.42 2010 2011 $0.45 $0.39 2010 2011 $3.06 $2.95 $0.30 $2.13 $0.26 $1.83 $1.79 $1.59 $0.17 Corporate & Other Carolinas Florida Consolidated Corporate & Other Carolinas Florida Consolidated ($0.14) ($0.17) *See appendix for reconciliation of ongoing EPS to reported GAAP EPS. 10 ($0.66) ($0.67)

EPS 4Q-2011 Ongoing EPS Drivers $0.70 $0.65 $0.03 $0.01 $0.01 $0.01 ($0.21) $0.60 $0.06 $0.55 $0.09 $0.50 $0.45 $0.45 $45M amortization of cost of removal obligation in 4Q-11 versus $0 in 4Q-10 ($0.05) $0.40 ($0.01) $0.39 $0.35 $0.30 $0.25 $0.20 2010 Ongoing EPS* O&M Deprec. & Amort. Clauses & Other Margin AFUDC Equity Interest Expense Income Taxes Weather Wholesale Other 2011 Ongoing EPS* *See appendix for reconciliation of ongoing EPS to reported GAAP EPS. 11

EPS 2011 Ongoing EPS Drivers $3.80 $3.60 $0.07 $0.04 $0.04 $0.01 ($0.45) $0.13 $3.40 $3.20 $0.31 Includes ($0.05) storm costs and $0.05 DOE spent fuel litigation at PEC ($0.15) Includes ($0.08) disallowance of replacement power at PEC $3.00 $2.80 $3.06 $250M amortization of cost of removal obligation in 2011 versus $60M in 2010 ($0.05) ($0.03) ($0.02) ($0.01) $2.95 $2.60 2010 Ongoing EPS* Deprec. & Amort. O&M Clauses & Other Margin AFUDC Equity Interest Expense Income Taxes Weather Wholesale Share Dilution Other Operating Other Retail Growth & Usage 2011 Ongoing EPS* *See appendix for reconciliation of ongoing EPS to reported GAAP EPS. 12

2011 Retail Sales (As of 12/31/2011) Progress Energy Carolinas (Change vs. prior year) Progress Energy Florida (Change vs. prior year) Residential -7.8% -0.8% Residential -9.7% 2.7% Commercial -3.6% -1.4% Commercial -2.0% -1.3% Industrial -0.9% -0.9% Industrial -0.7% -0.7% Total Retail -4.6% -0.9% Total Retail -6.1% 0.6% -10% -8% -6% -4% -2% 0% 2011 Carolinas Retail kwh Sales Actual Growth & Usage (0.9%) Weather (3.7%) Total Retail Sales (4.6%) 2011 Total Retail Sales Budget + 0.8% Weather-normalized -12% -10% -8% -6% -4% -2% 0% 2% 4% 2011 Florida Retail kwh Sales Growth & Usage 0.6% Weather (6.7%) Total Retail Sales (6.1%) 2011 Total Retail Sales Budget + 0.7% Note: Change in unbilled allocated to customer classes. 13

Dec-05 Apr-06 Aug-06 Dec-06 Apr-07 Aug-07 Dec-07 Apr-08 Aug-08 Dec-08 Apr-09 Aug-09 Dec-09 Apr-10 Aug-10 Dec-10 Apr-11 Aug-11 Dec-11 Customer Growth & Usage 35,000 Average Customer Growth* (000s) 95 Residential Customers Using Less Than 200 kwh Per Month 7.0% 30,000 90 25,000 85 6.5% 20,000 15,000 80 75 6.0% 10,000 70 5.5% 5,000 65 0 1Q07 3Q07 1Q08 3Q08 1Q09 3Q09 1Q10 3Q10 1Q11 3Q11 60 5.0% -5,000-10,000 PEC *Approximate average net increase in number of customers for respective three-month periods compared to prior year. PEF 14 PEF # of low-usage accounts PEF % low-usage customers PEC # of low-usage accounts PEC % low-usage customers

Crystal River Unit 3 Nuclear Outage PEF filed comprehensive settlement agreement in Docket #120022-EI which provides regulatory recovery guidelines related to unit Continuing discussions with NEIL for full recovery Reclassified $222M from NEIL receivable to deferred fuel regulatory asset ($154M) and CWIP ($68M) Accounting standards require insurance receivable to be probable of full recovery ($M) Repair Costs As of December 31, 2011 ($M) Replacement Power Costs $300 $500 $478 ($162) $258 ($136) $250 $400 $200 $150 $100 ($3) $119 $300 $200 ($55) $261 $50 $100 $- Spent to Date NEIL Proceeds Received NEIL Insurance Receivable Balance for Base Rate Recovery $- Spent to Date NEIL Proceeds Received NEIL Insurance Receivable Balance for Clause 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 15 *Balance to be recovered through annual fuel clause proceeding.

EPS 2012 Ongoing EPS Drivers $3.40 $3.20 PEC: $0.01 OATT changes PEF: $0.07 OATT true-up; rate changes $3.03 ($0.08) $0.09 $0.09 $0.08 $0.08 $0.06 ($0.05) ($0.04) PEC: $0.04 DSM/EE PEF: $0.02 Misc. revenues ($0.04) ($0.03) ($0.01) $3.18 $3.00 $2.80 $2.60 $2.95 2011 items: ($0.08) disallowance of replacement power ($0.05) storm costs $0.05 DOE spent fuel litigation $2.40 2011 Ongoing EPS* Weather Growth & Usage Wholesale AFUDC Equity Transmission Clauses & Other Margin Deprec. & Amort. Share Dilution Pension PEF Cost of Removal Interest Expense 2012 Ongoing EPS* *See appendix for reconciliation of ongoing EPS to reported GAAP EPS. 16

$ in Millions Wholesale Base Revenues $400 $350 $300 $250 $200 $150 $100 $50 $0 2007 2008 2009 2010 2011 2012E PEC PEF Carolinas Fayetteville contract extension mid-2012 Existing partial requirements, fixed price contract expires Jun-12 New 20-yr full requirements, formula-rate contract begins Jul-12 NCEMC contract expansion in 2013 New 20-yr power supply coordination agreement (PSCA) Immediate incremental 900+ MW load on top of the existing 1,200+ MW under contract today Beginning in 2013, PEC will supply the majority of NCEMC s load within the PEC control area and will serve future NCEMC load growth NCEMC load served by PEC is expected to grow to ~2,750 MW by the end of the contract term Florida Future Wholesale Upside New SECI contract beginning in 2012 17

Rate Base (x 1M) Rate Base (x 1M) Attractive Rate Base Growth Carolinas Florida $12,000 $12,000 $11,000 $11,000 $10,000 $10,000 $9,000 $9,000 $8,000 $8,000 $7,000 $7,000 $6,000 $6,000 $5,000 $5,000 $4,000 $4,000 $3,000 $3,000 $2,000 $2,000 $1,000 $1,000 $0 2010A 2011A 2012E 2013E 2014E $0 2010A 2011A 2012E 2013E 2014E NC SC Wholesale Retail Rate Base Clause-related Wholesale * *Represents ECRC (CAIR at CR4 & 5), Levy Nuclear, CR3 Nuclear Uprate and ECCR. 18

Major Capital Projects Lee CCGT North Carolina Major Construction Projects ($M) 920 MW combined-cycle gas-fired plant Project broke ground in September 2010 Expected in-service in January 2013 $750 $225 $600 Sutton CCGT North Carolina 625 MW combined-cycle gas-fired plant Project broke ground in May 2011 Expected in-service in December 2013 Smart Grid Carolinas & Florida $525 $340 $320 $95 Accepted $200M grant from the DOE in April 2010 ($100M each for PEC and PEF) Leverages already-planned investments of $320M ($200M for PEC and $120M for PEF) $260 $225 Lee* Sutton* Smart Grid Spent as of 12/31/11. Estimated expenditures to complete project. *Project costs include direct capital, AFUDC and the cost of all transmission additions and upgrades necessary to integrate the generator into the system. 19

Projected Capital Expenditures* ($ in millions) 2011A 2012E 2013E 2014E Maintenance Capex Generation $630 $690 $745 $755 Environmental 7 50 90 205 Transmission 100 100 120 100 Distribution 158 190 225 230 Other 88 80 100 80 Total Maintenance Capex 983 1,110 1,280 1,370 Growth Capex Generation 560 330 165 60 Transmission 171 260 210 190 Distribution / Other 235 190 240 290 Total Growth Capex 966 780 615 540 Corporate/other 16 30 30 30 Total Capital before Potential New Nuclear 1,965 1,920 1,925 1,940 New nuclear development 63 50-150 50-150 TBD Total Capital Spending $2,028 $1,970-$2,070 $1,975 -$2,075 $1,940 Total PEC (excluding new nuclear) 1,206 1,250 1,125 1,160 Total PEF (excluding new nuclear) 743 640 770 750 *Excludes CR3 Repair, CR3 Uprate, AFUDC, nuclear fuel and nuclear decommissioning trust funding. 20

Projected Cash Flow ($ in millions) 2011A 2012E Adjusted cash flow $1,949 $2,560 Pension fund contributions (pre-tax) 1 (334) (175) Operating cash flow 1,615 2,385 Nuclear fuel and decommissioning trust (275) (210) Maintenance & corporate/other capex 2 (999) (1,140) AFUDC debt (35) (35) Common dividends (734) (740) Free cash flow before growth capex (428) 260 Growth capex 2 (966) (780) New nuclear development 3 (63) (100) Free cash flow $(1,457) $(620) 1. Midpoint of range in 2012 ($125M-$225M). 2. Excludes CR3 repairs and uprate in 2012. 3. Midpoint of range in 2012 ($50M-$150M). 21

2012 Financing Plan Progress Energy, Inc. Refinance $450 million maturity due April 15, 2012 Equity issuances of approximately $300 million in second half of year if merger does not close in a timely manner Progress Energy Carolinas Refinance $500 million maturity due July 15, 2012 Additional long-term debt issuances up to $750 million Progress Energy Florida Refinance $425 million maturity due March 1, 2013 Potential additional long-term debt issuances depending on CR3 capital spending and replacement power recovery 22

Appendix Item Slides 2012 Earnings Guidance Support 24 27 Fixed Income Support 28 31 Reconciliation of Ongoing Earnings 32 34 23

2012 Earnings Guidance Support 24

GWh GWh Weather-Normalized Retail Sales Progress Energy Carolinas Progress Energy Florida 50,000 50,000 (0.8%) (2.7%) +2.0% (0.9%) +1.5% 40,000 40,000 (1.7%) (4.0%) (1.8%) +0.6% (0.4%) 30,000 30,000 20,000 20,000 10,000 10,000-2007 2008 2009 2010 2011 2012E - 2007 2008 2009 2010 2011 2012E Residential Commercial Industrial Governmental 25

Depreciation & Amortization Progress Energy Carolinas $600 ($ in millions) Cost of removal $600 Progress Energy Florida $500 $400 $300 Storm cost deferral amortization GridSouth amortization Nuclear recovery amortization Harris nuclear depreciation 1 $500 $400 $300 $200 $100 $200 Clean Smokestacks Act amortization 2 $0 2007A 2008A 2009A 2010A 2011A 2012E $100 Nuclear decommissioning cost provision 3 Depreciation of utility plant and other -$100 -$200 $0 2007A 2008A 2009A 2010A 2011A 2012E -$300 1. Harris nuclear depreciation minimum completed in North Carolina in 4 th quarter 2008 and terminated in South Carolina, effective October 22, 2008. 2. Clean Smokestacks Act amortization ceased, effective September 5, 2008. 3. Due to offsetting regulatory accounting entries, this has no impact on net income. 26

Allowance for Funds Used During Construction (AFUDC) Carolinas 1 Florida 2 $140 ($ in millions) $140 $120 $120 $100 $100 AFUDC - Debt $80 3 AFUDC - Equity $80 $60 $60 $40 $40 $20 $20 $0 2007A 2008A 2009A 2010A 2011A 2012E $0 2007A 2008A 2009A 2010A 2011A 2012E 1. PEC capital projects lasting more than one month are forecast to earn 8-9% AFUDC rate. 2. PEF capital projects greater than $65 million and lasting more than one year earn a 7.44% AFUDC rate. PEF has a base level of CWIP embedded in its rate base. 3. AFUDC equity is excluded from the calculation of income tax expense. 27

Fixed Income Support 28

Liquidity Position and Near-Term Debt Maturities ($ in millions) Liquidity position (as of December 31, 2011) Near-term debt maturities (as of December 31, 2011) PGN PEC PEF $1,978 ($673) $0 $950 $230 $1,535 $830 $500 $425 $450 $405 $300 Total credit facilities Drawn Short-term debt and facilitybacked letters of credit Cash & cash equivalents Total liquidity 2012 2013 2014 29

Capitalization and Short-Term Debt ($ in millions) As of December 31, 2011 PGN Consol. % PEC % PEF % Short-term Debt 1 $ 671 2.8% $ 219 2.3% $ 241 2.5% Current Portion of Long-term Debt 950 4.0% 500 5.2% - 0.0% Capital Lease Obligations 211 0.9% 12 0.1% 199 2.1% Long-term Debt Long-term Debt, affiliate 2 273 1.1% - 0.0% - 0.0% Long-term Debt, net 11,718 48.9% 3,693 38.6% 4,482 46.5% Total Debt $ 13,823 57.7% $ 4,424 46.2% $ 4,922 51.1% Preferred Stock of Subsidiaries 93 0.4% 59 0.6% 34 0.4% Noncontrolling Interests 4 0.0% - 0.0% - 0.0% Common Stock Equity 10,021 41.9% 5,088 53.2% 4,675 48.5% Total Capitalization and Short-term Debt $ 23,941 100.0% $ 9,571 100.0% $ 9,631 100.0% 1. Includes short-term debt and notes payable to affiliated companies. 2. Represents 7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Florida Progress Funding Corporation, a wholly owned subsidiary, to FPC Capital I, a wholly owned trust, in connection with the issuance of 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A by FPC Capital I. 30

Credit Ratings As of February 15, 2012 Progress Energy Moody s S&P 1 Fitch 2 Outlook Stable Watch Positive Stable Corporate Credit Rating -- BBB+ BBB Senior Unsecured Debt Baa2 BBB BBB Commercial Paper P-2 A-2 F2 Progress Energy Carolinas Outlook Stable Watch Positive Stable Corporate Credit Rating A3 BBB+ A- Commercial Paper P-2 A-2 F1 Senior Secured Debt A1 A A+ Senior Unsecured Debt A3 BBB+ A Preferred Stock Baa2 BBB- BBB+ Progress Energy Florida Outlook Stable Watch Positive Negative Corporate Credit Rating Baa1 BBB+ BBB+ Commercial Paper P-2 A-2 F2 Senior Secured Debt A2 A A Senior Unsecured Debt Baa1 BBB+ A- Preferred Stock Baa3 BBB- BBB 1. On January 10, 2011, S&P placed the corporate credit and issue ratings of Progress Energy and its subsidiaries on CreditWatch with positive implications. 2. On July 1, 2011, Fitch affirmed the ratings of Progress Energy and PEC with stable outlooks and affirmed the ratings of PEF with a negative outlook. 31

Reconciliation of Ongoing Earnings 32

Reconciliation of Ongoing to GAAP Earnings (Unaudited) Progress Energy, Inc. Reconciliation of Ongoing Earnings per Share to Reported GAAP Earnings per Share Three Months Ended December 31 Years Ended December 31 2011 2010 2011 2010 2009 Ongoing earnings per share $0.39 $0.45 $2.95 $3.06 $3.03 Tax levelization - (0.01) - - - CVO mark-to-market - - (0.16) - 0.07 Change in tax treatment of the Medicare Part D subsidy - - - (0.08) - Impairment (0.01) (0.01) (0.01) (0.02) (0.01) Plant retirement charges (0.01) - - - (0.06) Cumulative prior period adjustment - - - - (0.04) CR3 indemnification adjustment (charge) 0.01 - (0.06) - - Merger and integration costs (0.03) - (0.16) - - Amount to be refunded to customers (0.60) - (0.60) - - Discontinued operations - (0.01) (0.02) (0.01) (0.28) Reported GAAP earnings per share $(0.25) $0.42 $1.94 $2.95 $2.71 Shares outstanding (millions) 296 294 296 291 279 33

Ongoing Earnings Adjustments Progress Energy s management uses ongoing earnings per share to evaluate the operations of the company and to establish goals for management and employees. Management believes this non-gaap measure is appropriate for understanding the business and assessing our potential future performance, because excluded items are limited to those that we believe are not representative of our fundamental core earnings. Ongoing earnings as presented here may not be comparable to similarly titled measures used by other companies. Progress Energy is not able to provide a corresponding GAAP equivalent for the 2011 earnings guidance figures due to the uncertain nature and amount of these adjustments. 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 does not consider this item to be representative of the company s fundamental core earnings. Contingent Value Obligation (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 are recognized in earnings each quarter. Progress Energy is unable to predict the changes in the fair value of the CVOs, and management does not consider this item to be representative of the company s fundamental core earnings. Change in the Tax Treatment of the Medicare Part D Subsidy The federal Patient Protection and Affordable Care Act (PPACA) and the related Health Care and Education Reconciliation Act, which made various amendments to the PPACA, were enacted in March 2010. Under prior law, employers could claim a deduction for the entire cost of providing retiree prescription drug coverage even though a portion of the cost was offset by the retiree drug subsidy received. As a result of the PPACA, as amended, retiree drug subsidy payments will effectively become taxable in tax years beginning after Dec. 31, 2012, by requiring the amount of the subsidy received to be offset against the employer s deduction. Under GAAP, changes in tax law are accounted for in the period of enactment. Management does not consider this item to be representative of the company s fundamental core earnings. Impairment The company has recorded impairments of certain miscellaneous investments and other assets. Management does not consider these items to be representative of the company s fundamental core earnings. Plant Retirement Charges The company recognized charges for the impact of PEC s decision to retire certain coal-fired generating units, with resulting reduced emissions for compliance with the Clean Smokestacks Act s emission targets. Since the coal-fired generating units will be retired prior to their estimated useful lives, management does not consider this charge to be representative of the company s fundamental core earnings. Cumulative Prior Period Adjustment In the fourth quarter of 2009, PEC recorded a cumulative prior period adjustment related to certain employee life insurance benefits. Management does not consider this adjustment 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 does 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 does not consider this item to be representative of the company s fundamental core earnings. Amount to be Refunded to Customers The company recorded a charge for an amount to be refunded to PEF customers through the fuel clause in accordance with the proposed 2012 settlement agreement. Management does not consider this item to be representative of the company s fundamental core earnings. Discontinued Operations The company has completed its business strategy of divesting nonregulated businesses to reduce its business risk and focus on core operations of the Utilities. Management does not consider this item to be representative of the company s fundamental core earnings. 34