The NCUC, PSCSC, FPSC, IURC, PUCO and KPSC approve rates for retail electric and gas services within their states. Nonregulated sellers of gas and electric generation are also allowed to operate in Ohio once certified by the PUCO. The FERC approves rates for electric sales to wholesale customers served under cost-based rates, as well as sales of transmission service.

On February 4, 2013, Duke Energy Carolinas filed an application with the NCUC for an increase in base rates of approximately $446 million, or an average 9.7 percent increase in retail revenues. The request for increase is based upon an 11.25 percent return on equity and a capital structure of 53 percent equity and 47 percent long-term debt. The rate increase is designed primarily to recover the cost of plant modernization, environmental compliance and other capital additions.

Duke Energy Carolinas expects revised rates, if approved, to go into effect late third quarter of 2013.

On March 18, 2013, Duke Energy Carolinas filed an application with the PSCSC for an increase in base rates of approximately $220 million, or an average 15.1 percent increase in retail revenues. The request for increase is based upon an 11.25 percent return on equity and a capital structure of 53 percent equity and 47 percent long-term debt. More than half of the request is driven by capital investments, but also seeks to recover items such as vegetation management improvements, nuclear safety upgrades, cyber-security enhancements and the impacts of lower sales volumes.

Duke Energy Carolinas expects revised rates, if approved, to go into effect late third quarter of 2013.

On January 27, 2012, the NCUC approved a settlement agreement between Duke Energy Carolinas and the North Carolina Utilities Commission Public Staff (Public Staff) for a rate increase. On March 28, 2012, the North Carolina Attorney General (NCAG) filed a notice of appeal with the NCUC challenging the rate of return approved in the agreement. On April 12, 2013, the North Carolina Supreme Court (NCSC) issued an order requiring the NCUC to make an independent determination regarding the proper return on equity. The NCSC indicated the determination should be based upon appropriate findings of fact that balance all the available evidence, including the impact of changing economic conditions on customers. On April 29, 2013, the NCAG filed a motion with the NCUC requesting a stay of the rate increase approved by the NCUC and implemented in 2012. The NCAG also requested the NCUC to provide the parties guidance with respect to further evidentiary hearings at which new evidence would be introduced. On May 1, 2013, Duke Energy Carolinas filed its opposition to the NCAG's motion to stay the rate increase.

In December 2007, Duke Energy Carolinas filed an application with the NRC, which has been docketed for review, for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station (Lee Nuclear Station) at a site in Cherokee County, South Carolina. Each reactor is capable of producing 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC have concurred with the prudency of Duke Energy incurring certain project development and pre-construction costs. As of March 31, 2013, Duke Energy Carolinas has incurred approximately $330 million, including allowance for funds used during construction (AFUDC), which is included in Net property, plant and equipment on the Condensed Consolidated Balance Sheets.

The Lee COL application is impacted by the ongoing activity by the NRC to address its Waste Confidence rule, a generic finding by the NRC that spent fuel can be managed safely until ultimate disposal. The rule has been remanded to the NRC by the District of Columbia Court of Appeals. In response to the court's remand and in connection with numerous petitions asserting waste confidence contentions, including in the Lee proceeding, the NRC determined that no final licenses for new reactors would be issued until the remand is appropriately addressed. In September 2012, the NRC provided a timeline of 24 months from the time of its order for the staff to finish the generic Environmental Impact Study and publish a final Waste Confidence rule. Assuming the NRC uses the entire 24 month period for promulgation of a new rule, licenses would not be issued until September 2014 at the earliest.

In July 2011, Duke Energy Carolinas signed a letter of intent with Santee Cooper related to the potential acquisition by Duke Energy Carolinas of a 5 percent to 10 percent ownership interest in the V.C. Summer Nuclear Station being developed by Santee Cooper and SCE&G near Jenkinsville, South Carolina. The letter of intent provided a path for Duke Energy Carolinas to conduct the necessary due diligence to determine whether future participation in this project is beneficial for its customers. On November 7, 2012, the term of the letter of intent expired, though Duke Energy Carolinas remains engaged in discussions at this time.

On February 28, 2013, the Public Staff filed a Settlement Agreement with the NCUC detailing additional terms of settlement with Duke Energy Progress in connection with the rate case filed on October 12, 2012. Pursuant to the Settlement Agreement between Duke Energy Progress and the Public Staff, the parties have agreed to a two year step-in to a total agreed upon net rate increase, with the first year providing for a $151 million, or 4.7 percent average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or 1.0 percent average increase in rates. This second year increase is a result of Duke Energy Progress agreeing to delay collection of financing costs on the construction work in progress for the L.V. Sutton (Sutton) combined cycle facility for one year. The Settlement Agreement is based upon a return on equity of 10.2 percent and a 53 percent equity component of the capital structure. The Settlement Agreement is subject to approval by the NCUC.

Duke Energy Progress expects revised rates, if approved, to go into effect in June 2013.

Duke Energy Progress is constructing a new 625 MW natural gas-fired generating facility at its existing Sutton Steam Station in New Hanover County, North Carolina. Total estimated costs at final project completion (including AFUDC) for the Sutton project, which is approximately 77 percent complete, are $600 million. The Sutton project is expected to be in service in the fourth quarter of 2013.

In 2006, Duke Energy Progress selected a site at its existing Shearon Harris Nuclear Station (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, Duke Energy Progress filed its COL application with the NRC for two Westinghouse Electric AP1000 reactors at Harris, which the NRC docketed on April 17, 2008. On May 2, 2013, Duke Energy Progress filed a letter with the NRC requesting the NRC to suspend its review activities associated with the COL at the Harris site. As of March 31, 2013, approximately $70 million, including AFUDC, is recorded in Net property, plant and equipment on the Condensed Consolidated Balance Sheet. Duke Energy Progress is seeking recovery of this amount.

On February 22, 2012, the FPSC approved a comprehensive settlement agreement among Duke Energy Florida, the Florida Office of Public Counsel and other consumer advocates. The 2012 FPSC Settlement Agreement will continue through the last billing cycle of December 2016. The agreement addresses four principal matters: (i) the Crystal River Unit 3 delamination prudence review then pending before the FPSC, (ii) certain customer rate matters, (iii) Duke Energy Florida's proposed Levy Nuclear Station (Levy) cost recovery, and (iv) cost of removal reserve. Refer to each of these respective sections below for further discussion.

In September 2009, Crystal River Unit 3 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 Crystal River Unit 3 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. Crystal River Unit 3 remained out of service while Duke Energy Florida conducted an engineering analysis and review of the new delamination and evaluated possible repair options.

Subsequent to March 2011, monitoring equipment detected additional changes and further damage in the partially tensioned containment building. Duke Energy Florida developed a repair plan which had a preliminary cost estimate of $900 million to $1.3 billion.

On February 5, 2013, following the completion of a comprehensive analysis and an independent review by Zapata Incorporated which estimated repair costs to be between $1.49 billion and $3.43 billion depending on the repair scope selected, Duke Energy announced its intention to retire Crystal River Unit 3. Duke Energy concluded that it did not have a high degree of confidence that repair could be successfully completed and licensed within estimated costs and schedule, and that it was in the best interests of Duke Energy Florida's customers, joint owners and Duke Energy's investors to retire the unit. On February 20, 2013, Duke Energy Florida filed with the NRC a certification of permanent cessation of power operations. Duke Energy Florida developed initial estimates of the cost to decommission the plant during its analysis of whether to repair or retire Crystal River Unit 3. With the final decision to retire, Duke Energy Florida is working to develop a comprehensive decommissioning plan, which will evaluate various decommissioning options and costs associated with each option. The plan will determine resource needs as well as the scope, schedule and other elements of decommissioning. Duke Energy Florida intends to use a safe storage (SAFSTOR) option for decommissioning. Generally, SAFSTOR involves placing the facility into a safe storage configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur, usually in 40 to 60 years. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning approved by the NRC. Once an updated site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed which resulted in an estimate in 2011 dollars of $989 million. Additional specifics about the decommissioning plan are being developed.

Duke Energy Florida maintains insurance for Crystal River Unit 3 through Nuclear Electric Insurance Limited (NEIL). NEIL provides for covered accidental property damage claims on an actual cash value basis up to $1.06 billion with a $10 million deductible per claim. The NEIL coverage does not include property damage to or resulting from the containment structure except full limit coverage does apply to decontamination and debris removal if required following an accident to ensure public health and safety or if property damage results from a terrorism event.

Throughout the duration of the Crystal River Unit 3 outage, Duke Energy Florida worked with NEIL for recovery of applicable repair costs and associated replacement power costs. Pursuant to a settlement agreement executed on March 28, 2013, between NEIL and Duke Energy Florida, on April 25, 2013, NEIL paid Duke Energy Florida an additional $530 million. Along with the $305 million which NEIL previously paid, Duke Energy Florida has received a total of $835 million in insurance proceeds. In accordance with the 2012 FPSC Settlement Agreement, NEIL proceeds received allocable to retail customers will be applied to replacement power costs incurred after December 31, 2012 through December 31, 2016.

Because Duke Energy Florida did not begin the repair of Crystal River Unit 3 prior to December 31, 2012 and has decided to retire the unit, per the 2012 FPSC Settlement Agreement, Duke Energy Florida will refund $40 million in 2015 and $60 million in 2016. Duke Energy Florida recorded a Regulatory liability for these refunds in the third quarter of 2012 related to these replacement power obligations.

As a result of the 2012 FPSC Settlement Agreement, Duke Energy Florida will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of Crystal River Unit 3 for the period from the beginning of the Crystal River Unit 3 outage through December 31, 2016.

As a result of the 2012 FPSC Settlement Agreement, Duke Energy Florida will be allowed to recover all remaining Crystal River Unit 3 investments and a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017.

Duke Energy Florida has reclassified all Crystal River Unit 3 investments, including property, plant and equipment, nuclear fuel, inventory, and other assets to a regulatory asset. In addition, as a result of Duke Energy Florida's decision to retire Crystal River Unit 3, the 2012 FPSC Settlement Agreement authorizes Duke Energy Florida to defer the retail portion of all Crystal River Unit 3 related costs including, but not limited to, operations and maintenance and property tax costs in a regulatory asset. A regulatory liability must also be established to capture the difference between, i) actual incurred operations and maintenance and property tax costs in a given year and, ii) the amount included in customer rates as established in Duke Energy Florida's most recent fully litigated base rate proceeding, effective 2010. Beginning in February 2013, the retail portion of operations and maintenance costs associated with Crystal River Unit 3 is being deferred to a regulatory asset. As of March 31, 2013 and December 31, 2012, $1,711 million and $1,637 million, respectively, have been recorded to Regulatory assets on Duke Energy Florida's Condensed Balance Sheets.

In accordance with the terms of the 2012 FPSC Settlement Agreement, Duke Energy Florida retained the sole discretion to retire Crystal River Unit 3 without challenge from the parties to the agreement. The FPSC will review the prudence of the retirement decision in what was previously titled Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Duke Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of what was previously titled Phase 3 of this regulatory docket. Additionally, Duke Energy Florida anticipates that the FPSC will review the costs included in the Crystal River Unit 3 regulatory asset as part of this pending proceeding. On March 1, 2013, an order was issued that Phase 2 and Phase 3 of the regulatory docket would be considered together in a single hearing. On April 26, 2013, the FPSC issued a procedural order on the matter and set final hearing dates to resolve all remaining issues on October 21, 2013 through October 23, 2013. Oral arguments were heard on April 30, 2013 on evidentiary issues.

Duke Energy Florida believes the decision to retire Crystal River Unit 3, the actions taken and costs incurred in response to the Crystal River Unit 3 delamination 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 exit cost to wind down the operations at the plant and decommission Crystal River Unit 3 could be material. Retirement of the plant could impact funding obligations associated with Duke Energy Florida's nuclear decommissioning trust fund.

Duke Energy Florida is a party to a master participation agreement and other related agreements with the joint owners of Crystal River Unit 3 which convey certain rights and obligations on Duke Energy Florida and the joint owners. In December 2012, Duke Energy Florida reached an agreement with one group of joint owners related to all Crystal River Unit 3 matters, and is engaged in settlement discussions with the other major group of joint owners.

In conjunction with the 2012 FPSC Settlement Agreement, Duke Energy Florida 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 return on equity range of 9.5 percent to 11.5 percent. Additionally, costs associated with Crystal River Unit 3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. Duke Energy Florida will accrue, for future rate-setting purposes, a carrying charge on the Crystal River Unit 3 investment until the Crystal River Unit 3 regulatory asset is recovered in base rates beginning with the first billing cycle of January 2017. If Duke Energy Florida's retail base rate earnings fall below the return on equity range, as reported on a FPSC-adjusted or pro-forma basis on a Duke Energy Florida monthly earnings surveillance report, Duke Energy Florida may petition the FPSC to amend its base rates during the term of the agreement. Refer to the discussion above regarding recovery of Crystal River Unit 3 investments.

Duke Energy Florida will refund $288 million to retail customers through its fuel clause. Duke Energy Florida 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. Duke Energy Florida has a regulatory liability recorded for these refunds.

On July 28, 2008, Duke Energy Florida filed its COL application with the NRC for two Westinghouse AP1000 reactors at its proposed Levy nuclear station, which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application. On March 26, 2013, the Atomic Safety and Licensing Board issued a decision finding that the NRC had carried its burden of demonstrating that its Final Environmental Impact Statement complies with the National Environmental Policy Act and applicable NRC regulatory requirements. A mandatory hearing conducted by the five NRC Commissioners is expected to occur in late 2013 or early 2014.

The Levy COL application is also impacted by the ongoing activity by the NRC to address its Waste Confidence rule, a generic finding by the NRC that spent fuel can be managed safely until ultimate disposal. The rule has been remanded to the NRC by the District of Columbia Court of Appeals. In response to the court's remand and in connection with numerous petitions asserting waste confidence contentions, including in the Levy proceeding, the NRC determined that no final licenses for new reactors would be issued until the remand is appropriately addressed. In September 2012, the NRC provided a timeline of 24 months from the time of its order for the staff to finish the generic Environmental Impact Study and publish a final Waste Confidence rule. Assuming the NRC uses the entire 24 month period for promulgation of a new rule, licenses would not be issued until September 2014 at the earliest.

In 2008, the FPSC granted Duke Energy Florida'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.

Duke Energy Florida currently estimates the in-service date for the first Levy unit to be 2024, with the second unit following 18 months later. The total estimated project cost is between $19 billion and $24 billion. As of March 31, 2013, Duke Energy Florida has a net unrecovered investment of approximately $343 million, including AFUDC, recorded on its Condensed Balance Sheets.

Under the terms of the 2012 FSPC Settlement Agreement, Duke Energy Florida began retail cost-recovery of its proposed Levy Nuclear Station effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement and continuing for a five-year period, with true-up of any actual costs not recovered during the 5-year period occurring in the final year. 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 cancellation costs, if Duke Energy Florida ultimately chooses to cancel that contract. Duke Energy Florida will not file for recovery of any new Levy costs that were not addressed in the 2012 FSPC Settlement Agreement before March 1, 2017 and will not begin recovering those costs from customers before the first billing cycle of January, 2018, unless otherwise agreed to by the parties to the agreement. In addition, the consumer parties will not oppose Duke Energy Florida continuing to pursue a COL for Levy. The 2012 FSPC Settlement Agreement also provides that Duke Energy Florida will treat the allocated wholesale cost of Levy as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. Duke Energy Florida will have the discretion, under certain circumstances, to accelerate and/or suspend such amortization in full or in part provided that it amortizes all of the regulatory asset by December 31, 2016.

The 2012 FPSC Settlement Agreement (Settlement Agreement) provides Duke Energy Florida the discretion to reduce cost of removal amortization expense by up to the balance in the cost of removal reserve until the earlier of (a) its applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 FPSC Settlement Agreement. Duke Energy Florida may not reduce amortization expense if the reduction would cause it to exceed the appropriate high point of the return on equity range, as established in the Settlement Agreement. Pursuant to the Settlement Agreement, Duke Energy Florida recognized a reduction in amortization expense of $56 million and $58 million for the three months ended March 31, 2013 and 2012, respectively. Duke Energy Florida had eligible cost of removal reserves of $58 million remaining at March 31, 2013, which is impacted by accruals in accordance with its latest depreciation study, removal costs expended, jurisdictional allocation changes and reductions in amortization expense as permitted by the Settlement Agreement.

On August 29, 2012, Duke Energy Ohio filed an application with the PUCO for the establishment of a charge, pursuant to Ohio's state compensation mechanism, for capacity provided consistent with its obligations as a Fixed Resource Requirement (FRR) entity for approximately $728 million. The application included a request for deferral authority and for a new tariff to implement the charge. The deferral being sought is the difference between its costs and market-based prices for capacity. The requested tariff would implement a charge to be collected via a rider through which such deferred balances will subsequently be recovered. 24 parties moved to intervene. Hearings were held in April 2013 and additional hearings are scheduled for May 2013. Under the current procedural schedule, Duke Energy Ohio expects an order in the second half of 2013.

On May 1, 2013, the PUCO approved a settlement agreement (Electric Settlement) between Duke Energy Ohio and all intervening parties in connection with an electric distribution case, filed in July 2012. The Electric Settlement provides for a net increase in electric distribution revenues of $49 million, or an average increase of 2.9 percent, based upon a return on equity of 9.84 percent. Revised rates will be effective in May 2013.

On May 1, 2013, the PUCO approved a settlement agreement (Gas Settlement) between Duke Energy Ohio and all intervening parties in connection with a gas distribution case, filed in July 2012. The Gas Settlement provides for no increase in base rates for gas distribution service, subject to the unresolved litigation over remediation costs associated with manufactured gas plants (MGP). The Gas Settlement is based upon a return on equity of 9.84 percent.

Duke Energy Ohio requested that MGP remediation costs be recovered through a rider with the amount of recovery subject to the results of litigation. Duke Energy Ohio has requested an annual revenue requirement of $22 million for its MGP remediation costs. Hearings for the MGP litigation began April 29, 2013.

Duke Energy Ohio expects revised rates, if approved, to go into effect in the second half of 2013.

Duke Energy Ohio, which includes its wholly owned subsidiary Duke Energy Kentucky, transferred control of its transmission assets to effect a Regional Transmission Organization (RTO) realignment from Midcontinent Independent System Operator, Inc. (MISO) to PJM Interconnection, LLC (PJM), effective December 31, 2011.

On December 16, 2010, the FERC issued an order related to MISO's cost allocation methodology surrounding Multi-Value Projects (MVP), a type of MISO Transmission Expansion Planning (MTEP) project cost. MISO expects that MVP will fund the costs of large transmission projects designed to bring renewable generation from the upper Midwest to load centers in the eastern portion of the MISO footprint. MISO approved MVP proposals with estimated project costs of approximately $5.2 billion prior to the date of Duke Energy Ohio's exit from MISO on December 31, 2011. These projects are expected to be undertaken by the constructing transmission owners from 2012 through 2020 with costs recovered through MISO over the useful life of the projects. Duke Energy Ohio has historically represented approximately five percent of the MISO system. On October 21, 2011, the FERC issued an order on rehearing in this matter largely affirming its original MVP order and conditionally accepting MISO's compliance filing as well as determining that the MVP allocation methodology is consistent with cost causation principles and FERC precedent. The order further stated that MISO's tariff withdrawal language establishes that once cost responsibility for transmission upgrades is determined, withdrawing transmission owners retain any costs incurred prior to the withdrawal date. In order to preserve its rights, Duke Energy Ohio filed an appeal of the FERC order in the D.C. Circuit Court of Appeals. The case was consolidated with appeals of the FERC order by other parties in the Seventh Circuit Court of Appeals.

On December 29, 2011, MISO filed with FERC a Schedule 39 to MISO's tariff. Schedule 39 provides for the allocation of MVP costs to a withdrawing owner based on the owner's actual transmission load after the owner's withdrawal from MISO, or, if the owner fails to report such load, based on the owner's historical usage in MISO assuming annual load growth. On January 19, 2012, Duke Energy Ohio filed with FERC a protest of the allocation of MVP costs to them under Schedule 39. On February 27, 2012, the FERC accepted Schedule 39 as a just and reasonable basis for MISO to charge for MVP costs, a transmission owner that withdraws from MISO after January 1, 2012. The FERC set for hearing whether MISO's proposal to use the methodology in Schedule 39 to calculate the obligation of transmission owners who withdrew from MISO prior to January 1, 2012 (such as Duke Energy Ohio) to pay for MVP costs is consistent with the MVP-related withdrawal obligations in the tariff at the time that they withdrew from MISO, and, if not, what amount of, and methodology for calculating, any MVP cost responsibility should be.

On March 28, 2012, Duke Energy Ohio filed a request for rehearing of FERC's February 27, 2012 order on MISO's Schedule 39. On December 19, 2012, the FERC Trial Staff submitted testimony in the Schedule 39 hearing proceeding in which its witness stated his opinion that Duke Energy Ohio should not be liable for any MVP costs. The role of the FERC Trial Staff is to act as an independent party in the proceeding; it has no judicial authority. The Schedule 39 hearing was held in April 2013. A FERC Administrative Law Judge presided over the hearing and is required to issue an initial decision by July 16, 2013.

Upon its exit from MISO on December 31, 2011, Duke Energy Ohio recorded a liability for its MISO exit obligation and share of MTEP costs, excluding MVP, which was recorded within Other in Current liabilities and Other in Deferred credits and other liabilities on Duke Energy Ohio's Condensed Consolidated Balance Sheets. In addition to these liabilities, Duke Energy Ohio may also be responsible for costs associated with MISO MVP projects. Duke Energy Ohio is contesting its obligation to pay for such costs. However, depending on the final outcome of this matter, Duke Energy Ohio could incur material costs associated with MVP projects, which are not reasonably estimable at this time. Regulatory accounting treatment will be pursued for any costs incurred in connection with the resolution of this matter.

The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio's recorded obligations related to its withdrawal from MISO.

On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a Certificate of Public Convenience and Necessity (CPCN) for the construction of a 618 MW IGCC power plant at Duke Energy Indiana's Edwardsport Generating Station in Knox County, Indiana with a cost estimate of $1.985 billion assuming timely recovery of financing costs related to the project. On January 25, 2008, Duke Energy Indiana received the final air permit from the Indiana Department of Environmental Management. The Citizens Action Coalition of Indiana, Inc. (CAC), Sierra Club, Inc. (Sierra Club), Save the Valley, Inc. (Save the Valley), and Valley Watch, Inc. (Valley Watch), all intervenors in the CPCN proceeding (collectively, the Joint Intervenors), have appealed the air permit.

Duke Energy Indiana experienced design modifications, quantity increases and scope growth above what was anticipated from the preliminary engineering design, which increased capital costs for the project. In January 2009, a new cost estimate was approved by the IURC for $2.35 billion (including $125 million of AFUDC). In April 2010, Duke Energy Indiana filed a revised cost estimate for the IGCC project requesting approval of the revised cost estimate of $2.88 billion (including $160 million of AFUDC). In June 2011, Duke Energy Indiana updated its cost forecast to $2.82 billion (excluding AFUDC). In October 2011, Duke Energy Indiana revised its project cost estimate to $2.98 billion (excluding AFUDC). In October 2012, Duke Energy Indiana further revised its projected cost estimate to $3.15 billion (excluding AFUDC).

On December 27, 2012, the IURC approved a settlement agreement finalized in April 2012, between Duke Energy Indiana, the Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana, on the cost increase for the construction of the project including subdockets before the IURC related to the project. This order resolved all then pending regulatory issues related to the project. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595 billion, including estimated AFUDC through June 30, 2012. Duke Energy Indiana is allowed to recover AFUDC after June 30, 2012 until customer rates are revised, with such recovery decreasing to 85 percent on AFUDC accrued after November 30, 2012. Duke Energy Indiana also agreed not to request a retail electric base rate increase prior to March 2013, with rates in effect no earlier than April 1, 2014.

The IURC modified the settlement agreement as previously agreed to by the parties to (i) require Duke Energy Indiana to credit customers for cost control incentive payments which the IURC found to be unwarranted as a result of delays that arose from project cost overruns and (ii) provide that if Duke Energy Indiana should recover more than the project costs absorbed by Duke Energy's shareholders through litigation, any surplus must be returned to the Duke Energy Indiana's ratepayers. On December 11, 2012, Duke Energy Indiana filed an arbitration action against General Electric Company (General Electric) and Bechtel Corporation (Bechtel) in connection with their work at the Edwardsport IGCC facility. Duke Energy Indiana is seeking damages of not less than $560 million. Duke Energy Indiana cannot predict the outcome of this matter.

Over the course of construction of the project, Duke Energy Indiana recorded pre-tax charges of approximately $897 million, related to the Edwardsport project including the settlement agreement discussed above. For the three months ended March 31, 2012, Duke Energy Indiana recorded pre-tax charges of $420 million related to the Edwardsport project. These charges were recorded in Operating revenues, Impairment charges and Operations, maintenance and other on Duke Energy's Condensed Consolidated Statements of Operations and Duke Energy Indiana's Condensed Consolidated Statements of Operations and Comprehensive Income.

The Joint Intervenors have appealed the IURC order approving the April 2012 settlement agreement and other related regulatory orders to the Indiana Court of Appeals. No briefing schedule has been set.

The project is scheduled to be in commercial operation by mid-2013. Additional updates to the cost estimate and schedule could occur through the completion of the plant.

The costs for the Edwardsport IGCC plant are recovered from retail electric customers via a tracking mechanism, the IGCC Rider. Duke Energy Indiana files information related to the IGCC Rider every six months. In the currently pending tenth semi-annual IGCC rider proceeding, Duke Energy Indiana is requesting recovery associated with the capped construction costs of the project and forecasted operating expenses for the period the plant is expected to be in-service. On April 11, 2013, the OUCC and the Joint Intervenors filed testimony. The OUCC requested additional information concerning the operating expenses, but otherwise did not dispute Duke Energy Indiana's calculated rider amounts. The Joint Intervenors recommended rate disallowances of financing charges due to the extension of the in-service date calculated at approximately $77 million, which they deemed to be imprudent. Additionally, the Joint Intervenors requested various ratemaking changes, including interest to be paid on the credit to be provided to customers pursuant to the IURC order on the April 2012 Settlement Agreement. Finally, the Joint Intervenors have requested the IURC to open a docket related to the future reliability of the plant. Duke Energy Indiana will respond in rebuttal testimony in May and an evidentiary hearing is scheduled for June 2013.

On June 28, 2012, Duke Energy Indiana filed with the IURC a plan for the addition of certain environmental pollution control projects on several of its coal-fired generating units in order to comply with existing and proposed environmental rules and regulations. The plan calls for a combination of selective catalytic reduction systems, dry sorbent injection systems for SO3 mitigation, activated carbon injection systems and/or mercury re-emission chemical injection systems. The capital costs are estimated at $395 million (excluding AFUDC). Duke Energy Indiana also indicated that it preliminarily anticipates the retirement of Wabash River Units 2 through 5 in 2015 and is still evaluating future equipment additions or retirement of Wabash River Unit 6. On April 10, 2013, the IURC issued an order approving the plan.

On June 8, 2012, the FERC conditionally approved the Progress Energy merger including Duke Energy and Progress Energy's revised market power mitigation plan, the Joint Dispatch Agreement (JDA) and the joint Open Access Transmission Tariff (OATT). The revised market power mitigation plan provides for the acceleration of one transmission project and the construction of seven other transmission projects (Long-term FERC Mitigation) and interim firm power sale agreements during the construction of the transmission projects (Interim FERC Mitigation). The Long-term FERC Mitigation is expected to increase power imported into the Duke Energy Carolinas and Duke Energy Progress' service areas and enhance competitive power supply options in the service areas. The construction of these projects will occur over the next two to three years. In conjunction with the Interim FERC Mitigation, Duke Energy Carolinas and Duke Energy Progress entered into power sale agreements with various counterparties that were effective with the consummation of the merger. These agreements, or similar power sale agreements, will be in place until the Long-term FERC Mitigation is operational. Under the agreements Duke Energy will deliver around-the-clock power during the winter and summer in quantities that vary by season and by peak period.

The FERC order requires an independent party to monitor whether the power sale agreements remain in effect during construction of the transmission projects and provide quarterly reports to the FERC regarding the status of construction of the transmission projects.

On June 25, 2012, Duke Energy and Progress Energy accepted the conditions imposed by the FERC.

On July 10, 2012, certain intervenors requested a rehearing seeking to overturn the June 8, 2012 order by the FERC. On August 8, 2012, FERC granted rehearing for further consideration.

Following the closing of the merger, Duke Energy's outside counsel reviewed Duke Energy's mitigation plan and discovered a technical error in the calculations. Duke Energy reported the error to the appropriate regulatory bodies and is working to determine whether additional mitigation measures are necessary. At this time, Duke Energy cannot predict the outcome of this matter.

The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10-20 years), and options being considered to meet those needs. The IRP's filed by the Subsidiary Registrants in 2013, 2012 and 2011 included planning assumptions to potentially retire by 2015, certain coal-fired generating facilities in North Carolina, South Carolina, Florida, Indiana and Ohio that do not have the requisite emission control equipment, primarily to meet Environmental Protection Agency (EPA) regulations that are not yet effective.

The table below contains the net carrying value of generating facilities planned for early retirement or being evaluated for potential retirement included in Property, plant and equipment, net on the Condensed Consolidated Balance Sheets. In addition to the amounts presented below, Duke Energy Progress and Duke Energy Indiana have $125 million and $60 million, respectively, of net carrying value related to previously retired generation facilities included in Regulatory assets on their Condensed Consolidated Balance Sheets.


		March 31, 2013
			Duke Energy		Duke Energy Carolinas^(b)(e)		Progress Energy		Duke Energy Progress^(c)(e)		Duke Energy Florida^(d)		Duke Energy Ohio^(f)		Duke Energy Indiana^(g)
Capacity (in MW)			3,954		910		1,448		575		873		928		668
Remaining net book value (in millions)^(a)		$	415	$	98	$	175	$	62	$	113	$	12	$	130

(a)	Included in Property, plant and equipment, net as of March 31, 2013, on the Condensed Consolidated Balance Sheets, unless otherwise noted.
(b)	Includes Riverbend Units 4 through 7, Lee Units 1 and 2 and Buck Units 5 and 6. Duke Energy Carolinas has committed to retire 1,667 MW in conjunction with a Cliffside air permit settlement, of which 587 MW have already been retired as of March 31, 2013. Duke Energy Carolinas retired 710 MW for Riverbend Units 4 through 7 and Buck Units 5 and 6 on April 1, 2013. Excludes 170 MW Lee Unit 3 that is expected to be converted to gas in 2014. The Lee Unit 3 conversion will be considered a retirement toward meeting the 1,667 MW retirement commitment.
(c)	Includes Sutton Station, which is expected to be retired by the end of 2013.
(d)	Includes Crystal River Units 1 and 2.
(e)	Net book value of Duke Energy Carolinas' Buck Units 5 and 6 of $68 million, and Duke Energy Progress' Sutton Station of $62 million is included in Generation facilities to be retired, net, on the Condensed Consolidated Balance Sheets at March 31, 2013.
(f)	Includes Beckjord Station Units 2 through 6 and Miami Fort Unit 6. Beckjord has no remaining book value. Beckjord Unit 1 was retired May 1, 2012.
(g)	Includes Wabash River Units 2 through 6.

Duke Energy continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any of these assets are retired. However, such recovery, including recovery of carrying costs on remaining book values, could be subject to future regulatory approvals and therefore cannot be assured.