The NCUC, the PSCSC and the FPSC approve rates for retail electric services within their states. The FERC approves rates for electric sales to certain wholesale customers served under cost-based rates, as well as sales of transmission service.

On October 12, 2012, PEC filed an application with the NCUC for an increase in base rates of approximately $387 million, or an average 12% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 55% equity and 45% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. The rate case includes a corresponding decrease in PEC's energy efficiency (EE) and demand side management (DSM) rider, resulting in a net requested increase of $359 million, or 11% increase in revenues.

PEC expects revised rates, if approved, to go into effect in the second or third quarter of 2013.

On June 29, 2012, and July 2, 2012, the NCUC and the PSCSC, respectively, approved the JDA between Duke Energy Carolinas and PEC. The JDA provides for joint dispatch of the generating facilities of both Duke Energy Carolinas and PEC for the purpose of reducing the cost of serving the native loads of both companies. As set forth in the JDA, Duke Energy Carolinas will act as the joint dispatcher, on behalf of both Duke Energy Carolinas and PEC. As joint dispatcher, Duke Energy Carolinas will direct the dispatch of both Duke Energy Carolinas' and PEC's power supply resources, determine payments between the parties for the purchase and sale of energy between Duke Energy Carolinas and PEC as a result of the JDA, and calculate and allocate the fuel cost savings to the parties as a result of the JDA.

PEC is in the process of constructing two new generating facilities, which consist of an approximately 920-MW combined cycle natural gas-fired generating facility at the HF Lee Energy Complex (Lee) in Wayne County, N.C., and an approximately 625-MW natural gas-fired generating facility at the L.V. Sutton plant (Sutton) in New Hanover County, N.C. Lee has an expected in-service date of December 2012 and Sutton has an expected in-service date of December 2013. Based on updated cost estimates, total costs (including allowance for funds used during construction [AFUDC]) for the Lee and Sutton projects are estimated to be approximately $750 million and $600 million, respectively.

In 2006, PEC selected a site at its existing Shearon Harris Nuclear Power Plant (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, PEC filed its combined license (COL) application with the NRC for two Westinghouse Electric AP-1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among PEF, the Florida Office of Public Counsel and other consumer advocates. The 2012 settlement agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: the Crystal River Nuclear Plant Unit 3 (CR3) delamination prudence review then pending before the FPSC, PEF's proposed Levy Nuclear Plant (Levy) cost recovery, and certain base rate issues. Refer to each of these respective sections for further discussion.

In September 2009, CR3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, it was determined that the concrete delamination at CR3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. CR3 has remained out of service while PEF conducted an engineering analysis and review of the new delamination and evaluates possible repair options.

Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur.

PEF worked with two potential vendors for repair work and received repair proposals from both vendors. After analyzing those proposals, PEF selected a single vendor that would be engaged to complete the repair of CR3 should the choice to repair be made. See discussion below regarding CR3 cost recovery and other provisions, as a result of a 2012 settlement agreement with the FPSC.

Based on an analysis of possible repair options performed by outside engineering consultants, PEF selected an option, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls. The preliminary cost estimate of $900 million to $1.3 billion is currently under review and could change following completion of further detailed engineering studies, vendor negotiations and final risk assessments. These engineering studies and risk assessments include analyses by independent entities currently in progress. The risk assessment process includes analysis of events that, although currently deemed unlikely, could have a significant impact on the cost estimate or feasibility of repair. This preliminary cost estimate and project scope are under review, as described further below, however, the cost estimate is trending upward.

In March 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the PEF CR3 repair plan, including the repair scope, risks, costs and schedule. In its final report, Zapata found that the current repair scope appears to be technically feasible, but there are significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair CR3, including; (i) an independent review of the current repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of PEF's previous bid information, which included cost estimate data from PEF, of which Zapata estimated costs of $1.55 billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the PEF scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming PEF performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months. The principal difference between Zapata's estimate and PEF's previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. PEF has filed a copy of the Zapata report with the FPSC and with the NRC. The FPSC held a status conference on October 30, 2012 to discuss Duke Energy's analysis of the Zapata report.

PEF continues to analyze the various aspects of the repair option as well as the option of early retirement. This analysis includes the evaluation of the potential implications to scope, cost estimate and schedule from the project risks identified in the Zapata report. A number of factors could affect the decision to repair, the return-to-service date and repair costs incurred, including, but not limited to, state regulatory and NRC reviews, insurance recoveries from Nuclear Electric Insurance Limited (NEIL), the ability to obtain builder's risk insurance with appropriate coverage, final engineering designs, vendor contract negotiations, the ultimate work scope completion, performance testing, weather and the impact of new information discovered during additional testing and analysis. We will proceed with the repair option only if there is a high degree of confidence that the repair can be successfully completed and licensed within the final estimated costs and schedule, and it is in the best interests of PEF's customers, the joint owners and Duke Energy's investors.

PEF maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at CR3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded the insurance coverage. PEF also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

PEF is continuing to work with NEIL for recovery of applicable repair costs and associated replacement power costs. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL has unresolved concerns and has not made any payments on the second delamination and has not provided a written coverage decision for either delamination. In addition, no replacement power reimbursements have been received from NEIL since May 2011. These considerations led us to conclude that it was not probable that NEIL will voluntarily pay the full coverage amounts that we believe them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, we have agreed to mediation prior to commencing any formal dispute resolution. We are in the process of providing information as requested by NEIL and currently have scheduled the mediation to commence in November 2012. Given the circumstances, accounting standards require full recovery to be probable to recognize an insurance receivable. As of September 30, 2012, PEF has no insurance receivables from NEIL related to either the first or second delamination. PEF continues to believe that all applicable costs associated with bringing CR3 back into service are covered under all insurance policies.

The following table summarizes the CR3 replacement power and repair costs and recovery, as discussed above, through September 30, 2012:

(in millions)			Replacement Power Costs		Repair Costs
Spent to date			$	573	$	324
NEIL proceeds received to date				(162)		(143)
	Balance for recovery^(a)		$	411	$	181

^(a)		See discussion below of PEF's ability to recover prudently incurred fuel and purchased power costs and CR3 repair costs.

As a result of the 2012 settlement agreement with the FPSC, PEF will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of CR3 for the period from the beginning of the CR3 outage through the earlier of the return of CR3 to commercial service or December 31, 2016. If PEF does not begin repairs of CR3 prior to the end of 2012, PEF will refund replacement power costs on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016.

As a result of the ongoing analysis of repair options, including scope, schedule, cost estimate and project risks, PEF has determined that it is unlikely to be in a position to begin the repair of CR3 prior to December 31, 2012. Consistent with the 2012 settlement agreement regarding the timing of commencement of repairs, PEF recorded a regulatory liability of $100 million related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in the Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2012.

In the event that repair activities continue beyond December 31, 2016, the parties are not prohibited from contesting PEF's right to recover replacement power costs incurred after 2016. The parties to the agreement maintain the right to challenge the prudence and reasonableness of PEF's fuel acquisition and power purchases, and other fuel prudence issues unrelated to the CR3 outage. All prudence issues from the steam generator project inception through the date of settlement approval by the FPSC are resolved.

To the extent that PEF pursues the repair of CR3, PEF will establish an estimated cost and repair schedule with ongoing consultation with the parties to the agreement. The established cost, to be approved by Duke Energy's Board of Directors, will be the basis for project measurement. If costs exceed the board-approved estimate, overruns will be split evenly between Duke Energy shareholders and PEF customers up to $400 million. The parties to the agreement agree to discuss the method of recovery of any overruns in excess of $400 million, with final decision by the FPSC if resolution cannot be reached. If the repairs begin prior to the end of 2012, the parties to the agreement waive their rights to challenge PEF's decision to repair and the repair plan chosen by PEF. In addition, there will be limited rights to challenge recovery of the repair execution costs incurred prior to the final resolution on NEIL coverage. The parties to the agreement will discuss the treatment of any potential gap between NEIL repair coverage and the estimated cost, with final decision by the FPSC if resolution cannot be reached. If the repairs do not begin prior to the end of 2012, the parties to the agreement reserve the right to challenge the prudence of PEF's repair decision, plan and implementation.

PEF also retains sole discretion and flexibility to retire the unit without challenge from the parties to the agreement. If PEF decides to retire CR3, PEF is allowed to recover all remaining CR3 investments and to earn a return on the CR3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity (ROE) set at 70 percent of the current FPSC-authorized ROE, no earlier than the first billing cycle of January 2017. The wholesale portion of CR3 investments, which are not covered by the 2012 settlement agreement, totals approximately $130 million as of September 30, 2012. The recoverability of the wholesale portion of CR3 will continue to be evaluated as decisions are made regarding repair or retirement. Recovery of the wholesale portion of CR3 under the retirement option is at risk based on prior treatment of early retired plants in wholesale rates. Any NEIL proceeds received after the settlement will be applied first to replacement power costs incurred after December 31, 2012, with the remainder used to write down the remaining CR3 investments. Retirement of the plant could impact funding obligations associated with PEF's nuclear decommissioning trust fund.

PEF believes the actions taken and costs incurred in response to the CR3 delaminations have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and repair and maintenance costs incurred until CR3 is returned to service could be material. Additionally, we cannot be assured that CR3 can be repaired and brought back to service until full engineering and other analyses are completed.

PEF is a party to a master participation agreement and other related agreements with the joint owners of CR3 which convey certain rights and obligations on PEF and the joint owners. PEF is meeting with the joint owners on a regular basis to discuss the parties' mutual obligations under these agreements and to better understand their views and positions on these issues. We cannot predict the outcome of this matter.

As a result of the 2012 settlement agreement, PEF will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current ROE range of 9.5 percent to 11.5 percent. PEF suspended depreciation expense and reversed certain regulatory liabilities associated with CR3 effective on the February 22, 2012 implementation date of the agreement, resulting in no adjustment for the three months ended September 30, 2012, and a $47 million benefit for the nine months ended September 30, 2012, which reduced O&M expense in its Statements of Operations and Comprehensive Income. Additionally, costs associated with CR3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. PEF will accrue, for future rate-setting purposes, a carrying charge on the CR3 investment until CR3 is returned to service and placed back into retail rate base. Upon return of CR3 to commercial service, PEF will be authorized to increase its base rates for the annual revenue requirements of all CR3 investments. In the month following CR3's return to commercial service, PEF's ROE range will increase to between 9.7 percent and 11.7 percent. If PEF's retail base rate earnings fall below the ROE range, as reported on a FPSC-adjusted or pro-forma basis on a PEF monthly earnings surveillance report, PEF may petition the FPSC to amend its base rates during the term of the agreement. See the discussion above regarding recovery of CR3 investments if the plant is retired.

PEF will refund $288 million to customers through the fuel clause. PEF will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. In 2011, the corresponding charge was recorded as a reduction of operating revenues in PEF's Statements of Operations and Comprehensive Income.

On July 30, 2008, PEF filed its COL application with the NRC for two Westinghouse Electric AP-1000 reactors at Levy, which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application. In 2008, the FPSC granted PEF's petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida's nuclear cost-recovery rule for Levy, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of PEF's annual nuclear cost recovery filing, PEF updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current low natural gas prices, PEF has shifted the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 settlement agreement. Although the scope and overnight cost for Levy, including land acquisition, related transmission work and other required investments, remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

Along with the FPSC's annual prudence reviews, we will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; DSM and EE programs; and availability and terms of capital financing. Taking into account these criteria, Levy is considered to be PEF's preferred baseload generation option.

Under the terms of the 2012 settlement agreement, PEF will begin residential cost-recovery of its proposed Levy project effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement and continuing for a five-year period. PEF will not recover any additional Levy costs from customers through the term of the agreement, or file for any additional recovery before March 1, 2017, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the COL and any engineering, procurement and construction (EPC) cancellation costs, if PEF ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose PEF continuing to pursue a COL for Levy. PEF will true up any actual costs not recovered during the five-year period.

The 2012 settlement agreement also provides that PEF will treat the allocated wholesale cost of Levy (approximately $60 million) as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. PEF will have the discretion to accelerate and/or suspend such amortization in full or in part provided that PEF amortizes all of the regulatory asset by December 31, 2016.

On March 29, 2012, PEF announced plans to convert the 1,010-MW Anclote Units 1 and 2 (Anclote) from oil and natural gas fired to 100 percent natural gas fired and requested that the FPSC permit recovery of the estimated $79 million conversion cost through the Environmental Cost Recovery Clause (ECRC). PEF believes this conversion is the most cost-effective alternative for Anclote to achieve and maintain compliance with applicable environmental regulations (See Note 5A). On September 13, 2012, the FPSC approved PEF's request to seek cost recovery through the ECRC. PEF anticipates that both converted units will be placed in service by the end of 2013.

The 2012 and 2010 settlement agreements provide PEF the discretion to reduce amortization expense (cost of removal component) by up to the balance in the cost of removal reserve until the earlier of (a) PEF's applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 settlement agreement at the end of 2016. PEF may not reduce amortization expense if the reduction would cause PEF to exceed the appropriate high point of the ROE range, as established in the settlement agreements. Pursuant to the settlement agreements, PEF recognized a reduction in amortization expense of $60 million and $71 million for the three months ended September 30, 2012 and 2011, respectively. PEF recognized reductions in amortization expense of $118 million and $205 million for the nine months ended September 30, 2012 and 2011, respectively. PEF had eligible cost of removal reserves of $169 million remaining at September 30, 2012, which is impacted by accruals in accordance with PEF's latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the settlement agreements.

On July 6, 2012, the NCUC issued an order initiating investigation and scheduling hearings addressing the timing of the Duke Energy Board of Directors' decision on July 2, 2012, to replace William D. Johnson with James E. Rogers as President and Chief Executive Officer (CEO) of Duke Energy, as well as other related matters.

Pursuant to the merger agreement, William D. Johnson, Chairman, President and CEO of Progress Energy became President and CEO of Duke Energy and James E. Rogers, Chairman, President and CEO of Duke Energy became Executive Chairman of Duke Energy upon close of the merger. Mr. Johnson subsequently resigned as the President and CEO of Duke Energy, effective July 3, 2012, and Mr. Rogers was appointed to be CEO.

Pursuant to the NCUC's July 6, 2012 order, Mr. Rogers appeared before the NCUC on July 10, 2012, and provided testimony regarding the approval and closing of the merger and his replacement of Mr. Johnson as the President and CEO of Duke Energy. On July 19, 2012, Mr. Johnson, as well as E. Marie McKee and James B. Hyler, Jr., both former members of the Progress Energy Board of Directors and current members of the post-merger Duke Energy Board of Directors, appeared before the NCUC. Ann M. Gray and Michael G. Browning, both members of the pre-merger and post-merger Duke Energy Board of Directors, appeared before the NCUC on July 20, 2012. All provided testimony on the timing of the decision to replace Mr. Johnson with Mr. Rogers, as well as other related matters.

The NCUC's order also requests that Duke Energy provide certain documents related to the issue for its review. Duke Energy also received an Investigative Demand issued by the North Carolina Department of Justice (NCDOJ) on July 6, 2012, requesting the production of certain documents related to the issues which are also the subject of the NCUC Investigation. Duke Energy's responses to these requests were submitted on August 7, 2012. On August 1, 2012, the NCUC engaged the law firm of Jenner & Block to conduct an investigation of these matters. That investigation is underway and to date has involved the production of more documents to the NCUC and a series of informal interviews by Jenner & Block of a number of persons with knowledge of these matters, including executive officers of Duke Energy. This process is ongoing and will also involve interviews of the members of the legacy Duke Energy Board of Directors.

Duke Energy has also been contacted by the SEC to explain the circumstances surrounding the NCUC investigation and shareholder lawsuits in connection with the closing of the merger of Duke Energy and Progress Energy. A meeting was held with the SEC staff in late October. Duke Energy intends to continue to assist the SEC staff, as they request.

PEC filed a plan with the NCUC and the PSCSC to retire all of its coal-fired generating facilities in the Carolinas that do not have scrubbers. On October 1, 2011, PEC retired the Weatherspoon coal-fired generating units, on September 15, 2012, PEC retired the Lee coal-fired generating units, and on October 1, 2012, PEC retired the Cape Fear coal-fired generating units and the H.B. Robinson Unit 1 coal-fired unit. PEC expects to retire the Sutton coal-fired facility by the end of 2013.

In addition, on October 1, 2012, PEC retired six combustion turbine units in North Carolina, totaling approximately 100 MW of capacity.

The net carrying value of the remaining facilities at September 30, 2012, of $164 million and the net carrying value of the retired facilities of $57 million are included in generation facilities to be retired, net and regulatory assets, respectively, in the Consolidated Balance Sheets. The net carrying value of the retired facilities is expected to be recovered over a 10-year period as presented in our updated depreciation study filed with the NCUC and PSCSC. However, such recovery, including recovery of carrying costs on remaining book values, could be subject to future regulatory approvals and therefore cannot be assured.

PEF is considering the impact pending environmental regulations may have on the Crystal River Units 1 and 2 coal-fired steam turbines (CR1 and CR2), and the possibility of retiring these plants (See Note 5A).

During the three months ended September 30, 2012, we recorded increases to asset retirement obligations of $813 million, including $684 million at PEC and $129 million at PEF, with offsetting increases to asset retirement costs, included in property, plant and equipment in the Balance Sheets. These increases are the result of conforming with Duke Energy's assumptions for the types of estimated costs in the obligations, primarily related to including nuclear spent fuel disposal in the calculation.