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 June 17, 2013, Duke Energy Carolinas filed a settlement agreement with the NCUC detailing the terms of a settlement with the North Carolina Utilities Commission Public Staff (Public Staff) in connection with its rate case filed on February 4, 2013. Pursuant to the settlement agreement, the parties have agreed to a three year step-in, with the first two years providing for $205 million, or a 4.5 percent average increase in rates, and the third year providing for rates to be increased by an additional $30 million, or 0.6 percent. The settlement agreement is based upon a return on equity of 10.2 percent and an equity component of the capital structure of 53 percent. The settlement agreement allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs. In order to mitigate the impact of the increase on customers, the settlement agreement provides for a $10 million shareholder contribution to agencies that provide energy assistance to low-income customers, and an annual reduction in the regulatory liability for costs of removal of $30 million for each of the first two years. Duke Energy Carolinas also agreed not to request additional base rate increases before September 2015. The settlement agreement is subject to approval by the NCUC. The NCUC held an evidentiary hearing on the settlement agreement and other issues in the case in July 2013.

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

On July 23, 2013, Duke Energy Carolinas filed a settlement agreement with the PSCSC detailing the terms of a settlement with the Office of Regulatory Staff, Wal-Mart Stores East, LP and Sam's East, Incorporated, the South Carolina Energy Users Committee, Public Works of the City of Spartanburg, South Carolina and the South Carolina Small Business Chamber of Commerce in connection with its rate case filed on March 18, 2013. Pursuant to the settlement agreement, the parties have agreed to a two year step-in, with the first year providing for approximately $80 million, or a 5.53 percent average increase in rates, and the second year providing for rates to be increased by an additional $38 million, or 2.63 percent. 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 allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs. In order to mitigate the impact of the increase on customers, the settlement agreement provides for approximately $4 million of contributions to agencies that provide energy assistance to low-income customers and for economic development, and a reduction in the regulatory liability for costs of removal of $45 million for the first year. Duke Energy Carolinas also agreed not to request additional base rate increases before September 2015. The settlement agreement is subject to approval by the PSCSC. The PSCSC held an evidentiary hearing on the settlement agreement and other issues in the case on July 31, 2013.

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 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 a decision requiring the NCUC to make an independent determination regarding the proper return on equity. The NCSC stated the determination should be based upon appropriate findings of fact that weigh 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 20, 2013, the NCUC ruled that the rate increase would stay in effect pending the outcome of the review. Duke Energy Carolinas cannot predict the outcome of these proceedings.

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 South Carolina Electric and Gas (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.

In December 2007, Duke Energy Carolinas filed an application with the NRC, which has been docketed for review, for a 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. 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 Carolinas incurring certain project development and pre-construction costs. As of June 30, 2013, Duke Energy Carolinas has incurred approximately $350 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 U.S. Court of Appeals for the District of Columbia (D.C. Circuit). 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. The COL is also impacted by the time required to fully respond to an NRC request for additional information that addresses seismic hazard evaluation resulting from recommendations of the Fukushima Near-Term Task Force. Due to the schedule for both fully responding and for NRC review of the response, the Lee COL is not expected until 2016.

On May 30, 2013, the NCUC approved a settlement agreement between Duke Energy Progress and the Public Staff. The terms of the agreement include a two year step-in, with the first year providing for a $147 million, or a 4.5 percent average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or a 1.0 percent average increase in rates. The 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 agreement is based upon a return on equity of 10.2 percent and an equity component of the capital structure of 53 percent. The settlement agreement allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs. In order to mitigate the impact of the increase on customers, the agreement provides for a $20 million contribution to agencies that provide energy assistance to low-income customers, and a reduction in the regulatory liability for costs of removal of $20 million for the first year. New rates went into effect on June 1, 2013.

On July 1, 2013, the NCAG filed a notice of appeal with the NCUC challenging the rate of return and capital structure approved in the settlement agreement. Duke Energy Progress cannot predict the outcome of this matter.

Duke Energy Progress is constructing a new 625 MW combined cycle 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 88 percent complete, are $570 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 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 has docketed for review. 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 a result of the decision to suspend the COL applications, during the second quarter of 2013, Duke Energy Progress recorded a pretax impairment charge of $22 million, which represents costs associated with the COL, which are not probable of recovery. As of June 30, 2013, approximately $47 million is recorded in Regulatory assets on Duke Energy Progress' Condensed Consolidated Balance Sheet.

On February 22, 2012, the FPSC approved a Stipulation and Settlement Agreement (2012 Settlement) among Duke Energy Florida, the Florida Office of Public Counsel (OPC) and other customer advocates. The 2012 Settlement will continue through the last billing cycle of December 2016, unless replaced as discussed below. 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.

The FPSC has an open proceeding to review Duke Energy Florida's February 2013 decision to retire Crystal River Unit 3, the mediated resolution of insurance claims with Nuclear Electric Insurance Limited (NEIL), the costs spent to repair Crystal River Unit 3 since the 2012 Settlement, the uprate project, and the amount of the regulatory asset to be placed in rates in 2017. On April 26, 2013, the FPSC set final hearings to resolve all remaining issues beginning October 21, 2013. On June 19, 2013, the FPSC granted a joint motion to extend the due dates for discovery and testimony by 30 days to allow time for the parties to finalize issues, coordinate depositions and discovery, and potentially resolve discovery disputes.

On August 1, 2013, Duke Energy Florida, OPC, and other customer advocates filed a Revised and Restated Stipulation and Settlement Agreement (2013 Settlement) with the FPSC. If approved, the 2013 Settlement will replace and supplant the 2012 Settlement and substantially resolve additional issues, including (i) matters related to Crystal River Unit 3, (ii) Levy, (iii) Crystal River 1 and 2 coal units, and (iv) future generation needs in Florida. The 2013 Settlement is subject to review and approval by the FPSC, which is expected by the end of 2013.

Refer to the remaining sections below for further discussion of these settlement agreements.

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 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 Florida announced its intention to retire Crystal River Unit 3. Duke Energy Florida 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 and permanent removal of fuel from the reactor vessel. 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.

At the time of the delamination, Duke Energy Florida maintained insurance coverage through NEIL's accidental property damage program, which provided insurance coverage up to $2.25 billion with a $10 million deductible per claim. Duke Energy Florida currently maintains insurance through NEIL's accidental property damage program provides coverage 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. On April 25, 2013, pursuant to a settlement agreement between NEIL and Duke Energy Florida, NEIL paid Duke Energy Florida $530 million related to the Crystal River Unit 3 delaminations. Duke Energy Florida has received a total of $835 million in insurance proceeds from NEIL. In accordance with the 2012 Settlement, the majority of NEIL proceeds received were allocable to retail customers and have been applied to replacement power costs incurred after December 31, 2012 through December 31, 2016 and repair costs as appropriate. As a result, Duke Energy Florida recorded a regulatory liability of $490 million upon receipt of the April 2013 NEIL settlement proceeds. This amount is being refunded to retail customers through Duke Energy Florida's fuel clause. Proceeds received from NEIL and the related refunds retail customers are presented in Operating Activities on Duke Energy Florida's Condensed Statements of Cash Flows.

Because repairs to Crystal River Unit 3 did not begin prior to December 31, 2012, and the unit has subsequently been retired, per the 2012 Settlement, Duke Energy Florida will refund $100 million to retail customers through its fuel clause (retirement decision refund). Duke Energy Florida recorded a Regulatory liability for these refunds in the third quarter of 2012 related to these replacement power obligations.

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 Settlement 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 and property taxes associated with Crystal River Unit 3 are being deferred to a regulatory asset. The 2013 Settlement terminates the regulatory asset and/or liability treatment for operating expenses incurred after December 31, 2013.

The 2013 Settlement resolves substantially all remaining issues in the FPSC proceeding related to the review of Duke Energy Florida's decision to retire Crystal River Unit 3, the mediated resolution of insurance claims with NEIL, and the costs spent to repair Crystal River Unit 3 since the decision to retire the unit in February 2013; the uprate project; and the components of the regulatory asset to be recovered in rates beginning in 2017 via a separate base rate component.

Under the 2013 Settlement, Duke Energy Florida agrees to forego recovery of $295 million of the Crystal River Unit 3 regulatory asset. This excludes amounts related to the uprate project, which will continue to be recovered through the Nuclear Cost Recovery Clause (NCRC) over a seven year period, from 2013 through 2019. Duke Energy Florida recorded a $295 million pretax charge in the second quarter of 2013 for this matter. This amount in included in Impairment charges on Duke Energy Florida's Condensed Statements of Operations and Comprehensive Income.

The 2013 Settlement allows Duke Energy Florida to accelerate cash recovery of approximately $135 million from retail customers from 2014 through 2016 of the Crystal River Unit 3 regulatory assets through its fuel clause.

The 2013 Settlement allows Duke Energy Florida to begin recovery of the remaining Crystal River Unit 3 regulatory asset, up to a cap of $1,466 million from retail customers upon the earlier of (i) full recovery of the uncollected Levy investment or (ii) the first billing period of January 2017. Recovery will continue 240 months from inception of the collection of the regulatory asset in base rates, and the Crystal River Unit 3 base rate component will be adjusted at least every four years. Included in this recovery, but not subject to the cap, are costs of building a dry cask storage facility for spent nuclear fuel, if needed. The return rate will be based on the currently approved AFUDC rate with a return on equity of 7.35 percent, or 70 percent of the currently approved 10.5 percent, subject to change if the return on equity changes in the future. Construction of the dry cask storage facility is subject to separate FPSC approval. The regulatory asset associated with the uprate project will continue to be recovered through the NCRC over an estimated seven year period beginning in 2013.

The following table includes the components of the Crystal River Unit 3 Regulatory assets recorded on Duke Energy Florida's Condensed Balance Sheet


(in millions)		June 30, 2013
Historical net book value^(a)		$	1,036
Operating expense deferrals^(b)			96
Carrying charges^(c)			33
Amount subject to cost cap			1,165
Uprate and dry cask storage projects			332
Total regulatory asset		$	1,497

(a)	Includes amounts previously classified as plant in service, construction work in process, nuclear fuel and materials and supplies inventory.
(b)	Includes operations and maintenance, property taxes and depreciation.
(c)	See discussion under Customer Rate Matters section below.

The following table includes a summary of the retail customer refunds agreed to in the 2012 Settlement and 2013 Settlement, amounts refunded to date and amounts to be refunded in future periods.

		June 30, 2013
						Remaining Amount to be Refunded
(in millions)		Total		Refunded to date		2013		2014		2015		2016
2012 Settlement refund^(a)		$	288	$	65	$	64	$	139	$	10	$	10
Retirement decision refund			100		―		―		―		40		60
NEIL proceeds			490		163		163		164		―		―
Total customer refunds		$	878		228		227		303		50		70
Accelerated regulatory asset recovery			(135)		―		―		(38)		(38)		(59)
Net customer refunds			743	$	228	$	227	$	265	$	12	$	11

(a)	See discussion under Customer Rate Matters section below.

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 regarding resolution of matters associated with Crystal River Unit 3.

Duke Energy Florida cannot predict the outcome of the matters described above. In the event the FPSC rejects the 2013 Settlement, orders additional concessions, or if costs exceed the cap, additional charges to expense, which could be material, could occur.

In conjunction with the 2012 Settlement, Duke Energy Florida was to maintain base rates at then current levels through the last billing cycle of December 2016, except as described as follows. The agreement provided for a $150 million increase in revenue requirements effective with the first billing cycle of January 2013. Costs associated with Crystal River Unit 3 investments were removed from retail rate base effective with the first billing cycle of January 2013. Duke Energy Florida is accruing, 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.

In addition to the refunds related to Crystal River Unit 3 mentioned above, Duke Energy Florida is refunding $288 million to retail customers through its fuel clause.

Pursuant to the 2013 Settlement Agreement, Duke Energy Florida will maintain base rates at the current level through the last billing period of 2018, subject to the return on equity range of 9.5 percent to 11.5 percent. Duke Energy Florida will not be required to file a depreciation study, fossil dismantlement study or nuclear decommissioning study until the earlier of the next rate case filing or March 31, 2019.

If Duke Energy Florida determines that additional amounts are necessary to fund the Crystal River Unit 3 decommissioning trust, it is permitted to petition for collection of those funds up to $8 million through a base rate surcharge. If the FPSC approves annual decommissioning funding prior to the end of 2018 in excess of the amount authorized for recovery in the base rate surcharge, the excess shall be deferred with a carrying costs and recovered through the Capacity Cost Recovery Clause beginning in January 2019, without having to file a general rate case.

On July 28, 2008, Duke Energy Florida filed its COL application with the NRC for two Westinghouse AP1000 reactors at Levy, which the NRC has docketed for review. 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 January 2015.

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.

Under the terms of the 2012 Settlement, Duke Energy Florida began retail cost-recovery of Levy costs 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 (EPC) agreement cancellation costs, should Duke Energy Florida ultimately choose to cancel that contract. The consumer parties will not oppose Duke Energy Florida continuing to pursue a COL for Levy. The 2012 Settlement provided 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 had 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.

Pursuant to the 2013 Settlement, Duke Energy Florida agrees to terminate the EPC at the earliest reasonable and prudent time. The EPC was based on receiving the COL by January 1, 2014, which will not occur as noted above. The 2013 Settlement provides for recovery of the EPC cancellation costs from customers. Duke Energy Florida will exercise best efforts to obtain the COL from the NRC prior to March 31, 2015. If Duke Energy Florida, at its own discretion, decides not to pursue the COL prior to March 31, 2015, it agrees to credit customers $10 million as a reduction to fuel costs.

Cost recovery shall terminate upon the earlier of (i) full recovery of Levy costs or (ii) the first billing cycle of January 2018, subject to a final true-up through the nuclear cost recovery clause.

In accordance with the 2013 Settlement, Duke Energy Florida will cease amortization of the wholesale allocation of Levy investments against retail rates. In the second quarter of 2013, Duke Energy Florida recorded a pretax charge of $65 million to write-off the wholesale portion of Levy investments. This amount is included in Impairment charges on Duke Energy Florida's Condensed Statements of Operations and Comprehensive Income.

The 2013 Settlement allows for full recovery of the remaining retail project costs within five years from 2013 through 2017. Duke Energy Florida has an ongoing responsibility to demonstrate prudency related to the wind down of the Levy investment and the potential for salvage of Levy assets. As of June 30, 2013, Duke Energy Florida has a net uncollected investment in Levy of approximately $281 million, including AFUDC. Of this amount, $143 million is included in Regulatory assets and $138 million, related to land and the COL, is included in Net, property, plant and equipment on Duke Energy Florida's Condensed Balance Sheets.

Pursuant to the 2013 Settlement, in the event Duke Energy Florida decides to retire the Crystal River 1 and 2 coal units in order to comply with certain environmental regulations, it will be allowed to continue to recover existing annual depreciation expense through the end of 2020. Beginning in 2021, Duke Energy Florida will be allowed to recover any remaining net book value of the assets from retail customers through the Capacity Cost Recovery Clause.

Duke Energy Florida currently projects a significant need for additional generation to offset the impact of the lost capacity resulting from the retirement of Crystal River Unit 3 as well as the possible retirement of the Crystal River 1 and 2 coal units. The 2013 Settlement establishes a recovery mechanism for additional generation needs. This recovery mechanism, the Generation Base Rate Adjustment (GBRA), will apply to (i) the construction, uprate of existing generation, and/or purchase of up to 1,150 MW of combustion turbine and/or combined cycle generating capacity prior to the end of 2017 and (ii) the construction of additional generation of up to 1,800 MW to be placed in service in 2018 upon FPSC approval of a need determination. Duke Energy Florida will be permitted to recover the prudent costs of these items through an increase in base rates, upon the in-service date of such assets, without a general rate case at a 10.5 percent return on equity.

The 2012 Settlement and 2013 Settlement provide 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; (b) the expiration of the 2012 Settlement, unless replaced; or (c) the expiration of the 2013 Settlement, if approved. 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. Duke Energy Florida recognized a reduction in amortization expense of $17 million for the three months ended June 30, 2013, and $73 million and $58 million for the six months ended June 30, 2013 and 2012, respectively. Duke Energy Florida recognized no reduction of amortization expense for the three months ended June 30, 2012. Duke Energy Florida had eligible cost of removal reserves of $41 million remaining at June 30, 2013, which is impacted by accruals in accordance with its latest depreciation study, removal costs expended, jurisdictional allocation changes and reductions in amortization expense.

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 $729 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 Duke Energy Ohio's embedded 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. Hearings concluded in 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 were effective in May 2013.

On April 2, 2013, Duke Energy Ohio reached a stipulation (Gas Settlement) with the PUCO Staff and 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. The Gas Settlement left unresolved the recovery of environmental remediation costs associated with former manufactured gas plants (MGP). The Gas Settlement is based upon a return on equity of 9.84 percent.

Duke Energy Ohio's original application requested that MGP remediation costs be recovered through base rates; however, the Gas Settlement establishes a rider for recovery of allowable costs subject to the result of additional litigation. Duke Energy Ohio has requested recovery of approximately $63 million for MGP remediation costs deferred, including carrying costs, through December 31, 2012. Hearings for the MGP litigation were completed in May 2013.

Duke Energy Ohio expects revised base rates, if approved, to go into effect in the second half of 2013. Upon receipt of the PUCO's order, Duke Energy Ohio will file an application to establish the MGP Rider based on the amount approved by the PUCO.

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 capital project costs of approximately $5.5 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, including an authorized rate of return and associated operating and maintenance expenses, recovered through MISO over the useful life of the projects. Duke Energy Ohio has historically represented approximately five percent of the MISO system. In 2011, MISO estimated Duke Energy Ohio's MVP obligation to be $514 million based on the future revenue requirements of the proposed MVP projects and using an 8.2% discount rate. This estimate could change significantly and is dependent in large part on which projects are actually constructed, the final costs to complete and operate the projects and the discount rate used to measure the liability, if the liability can be discounted when recorded. 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 June 7, 2013, the Seventh Circuit dismissed Duke Energy Ohio's appeal for lack of a final administrative decision on the matter.

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. The Schedule 39 hearing was held in April 2013. A FERC Administrative Law Judge (ALJ) presided over the hearing and issued an initial decision on July 16, 2013. The ALJ ruled that Schedule 39 is consistent with the MVP-related withdrawal obligations in the tariff at the time that Duke Energy Ohio withdrew from MISO and is otherwise just and reasonable. Thus, under the initial decision, Duke Energy Ohio would be liable for MVP costs. Duke Energy Ohio will file exceptions to the initial decision, requesting the FERC overturn the ALJ's decision. After reviewing the initial decision, along with all exceptions and responses to exceptions filed by the parties, the FERC will issue a final decision. Duke Energy Ohio fully intends to appeal to the federal court of appeals if the FERC affirms the ALJ's decision.

On December 22, 2010, the KPSC issued an order granting approval of Duke Energy Kentucky's request to effect the RTO realignment, subject to several conditions. The conditions accepted by Duke Energy Kentucky include a commitment to not seek to double-recover in a future rate case the transmission expansion fees that may be charged by the MISO and PJM in the same period or overlapping periods. On January 25, 2011, the KPSC issued an order stating that the order had been satisfied and is now unconditional.

On April 26, 2011, Duke Energy Ohio, Ohio Energy Group, The Office of Ohio Consumers' Counsel and the Commission Staff filed an Application and a Stipulation with the PUCO regarding Duke Energy Ohio's recovery via a non-bypassable rider of certain costs related to its proposed RTO realignment. Under the Stipulation, Duke Energy Ohio would recover all MTEP costs, including but not limited to MVP costs, directly or indirectly charged to Duke Energy Ohio retail customers. Duke Energy Ohio would not seek to recover any portion of the MISO exit obligation, PJM integration fees, or internal costs associated with the RTO realignment and the first $121 million of PJM transmission expansion costs from Ohio retail customers. Duke Energy Ohio also agreed to vigorously defend against any charges for MVP projects from MISO. On May 25, 2011, the Stipulation was approved by the PUCO. An application for rehearing filed by Ohio Partners for Affordable Energy was denied by the PUCO on July 15, 2011.

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 outcome of this matter, Duke Energy Ohio could incur material costs associated with MVP projects, which are not reasonably estimable at this time.

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 settlement agreement 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 and Bechtel Corporation 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. Of this amount, pre-tax impairment and other charges of $420 million were recorded during the six months ended June 30, 2012. These charges were recorded in 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. The Appellants' brief is due September 9, 2013, and a final decision is anticipated mid-2014.

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. The tenth semi-annual IGCC rider proceeding is currently pending, and testimony was filed for the eleventh semi-annual IGCC rider proceeding in July 2013. In both proceedings, Duke Energy Indiana has requested recovery associated with the capped construction costs of the project and forecasted operating expenses for the period the plant is in service.

On April 10, 2013, the IURC approved Duke Energy Indiana's filed 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 expenditures approved in the plan will be presented for recovery in Duke Energy Indiana's semi-annual environmental cost recovery rider. 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 June 8, 2012, the FERC conditionally approved the merger with Progress Energy, 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.

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. 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 Carolinas, Duke Energy Progress and Duke Energy Indiana have $73 million, $190 million and $59 million, respectively, of net carrying value related to previously retired coal generation facilities included in Regulatory assets on their Condensed Consolidated Balance Sheets.


		June 30, 2013
		Duke Energy		Duke Energy Carolinas		^(b)	Progress Energy		Duke Energy Progress		^(c)(e)	Duke Energy Florida		^(d)	Duke Energy Ohio		^(f)	Duke Energy Indiana		^(g)
Capacity (in MW)			3,244		200			1,448		575			873			928			668
Remaining net book value (in millions)^(a)		$	326	$	15		$	173	$	61		$	112		$	11		$	127

(a)	Included in Property, plant and equipment, net as of June 30, 2013, on the Condensed Consolidated Balance Sheets, unless otherwise noted.
(b)	Includes Lee Units 1 and 2. Excludes 170 MW Lee Unit 3 that is expected to be converted to gas in 2014.
(c)	Includes Sutton Station, which is expected to be retired by the end of 2013.
(d)	Includes Crystal River Units 1 and 2.
(e)	Remaining net book value of Duke Energy Progress' Sutton Station is included in Generation facilities to be retired, net, on the Condensed Consolidated Balance Sheets at June 30, 2013.
(f)	Includes Beckjord Station Units 2 through 6 and Miami Fort Unit 6. Beckjord has no remaining book value.
(g)	Includes Wabash River Units 2 through 6. Wabash River Unit 6 is being evaluated for potential conversion to gas.

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.