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 September 24, 2013, the NCUC approved a settlement agreement related to Duke Energy Carolinas' request for a rate increase with minor modifications. The North Carolina Utilities Commission Public Staff (Public Staff) was a party to the settlement agreement. The parties have agreed to a three year step-in rate increase, 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 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 (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $10 million shareholder contribution to agencies that provide energy assistance to low-income customers, and (iii) 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 to be effective before September 2015. New rates went into effect on September 25, 2013.

On October 23, 2013, the North Carolina Attorney General (NCAG) appealed the rate of return and capital structure approved in the agreement. On October 24, 2013, the NC Waste Awareness and Reduction Network (NC WARN) also appealed various matters in the settlement. Duke Energy Carolinas cannot predict the outcome of this matter.

On September 11, 2013, the PSCSC approved a settlement agreement related to Duke Energy Carolinas' request for a rate increase. Parties to the settlement agreement were 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. The parties agreed to a two year step-in rate increase, with the first year providing for approximately $80 million, or a 5.5 percent average increase in rates, and the second year providing for rates to be increased by an additional $38 million, or 2.6 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 (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) approximately $4 million of contributions to agencies that provide energy assistance to low-income customers and for economic development, and (iii) 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 to be effective before September 2015. New rates went into effect on September 18, 2013.

On January 27, 2012, the NCUC approved a settlement agreement related to Duke Energy Carolinas' request for a rate increase. The Public Staff was a party to the settlement. On March 28, 2012, the NCAG appealed the rate of return approved in the agreement. On April 12, 2013, the North Carolina Supreme Court (NCSC) ordered 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 October 23, 2013, the NCUC reaffirmed the rate of return approved in the January 27, 2012 settlement agreement. On October 25, 2013, the NCAG announced his intention to appeal the reaffirmed order. The appeal has not yet been filed. Duke Energy Carolinas cannot predict the outcome of this matter.

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 letter of intent expired. However, Duke Energy Carolinas remains engaged in discussions at this time.

In December 2007, Duke Energy Carolinas applied to the NRC 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. 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, although recovery of costs is not guaranteed. Duke Energy Carolinas has incurred approximately $370 million, including allowance for funds used during construction (AFUDC) through September 30, 2013. This amount is included in Net property, plant and equipment on Duke Energy Carolinas' Condensed Consolidated Balance Sheets.

The Lee COL application is impacted by the ongoing NRC activity to address its Waste Confidence rule. The Waste Confidence rule is a generic finding by the NRC that spent fuel can be managed safely until ultimate disposal. The U.S. Court of Appeals for the District of Columbia (D.C. Circuit) remanded the rule to the NRC. The NRC determined that no final licenses for new reactors would be issued until the remand is appropriately addressed. Based upon current timelines from the NRC, 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 addressing 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 related to Duke Energy Progress' request for a rate increase. The Public Staff was a party to the settlement agreement. The parties have agreed to a two year step-in rate increase, 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 (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $20 million contribution to agencies that provide energy assistance to low-income customers, and (iii) 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 appealed the NCUC's approval of the rate of return and capital structure included in the agreement. The NCSC recently docketed the appeal. Legal briefs are due in the fourth quarter of 2013. Duke Energy Progress cannot predict the outcome of this matter.

Duke Energy Progress is constructing a 625 MW combined cycle natural gas-fired generating facility at its existing Sutton Steam Station in New Hanover County, North Carolina. Total final project cost including AFUDC is estimated to be $570 million. The Sutton project is approximately 94 percent complete and expected to be in service in the fourth quarter of 2013.

On February 19, 2008, Duke Energy Progress applied to the NRC for a COL for two Westinghouse Electric AP1000 reactors at Harris. On May 2, 2013, Duke Energy Progress requested the NRC to suspend its review activities associated with the COL. As a result of the decision to suspend the COL applications, Duke Energy Progress recorded a pretax impairment charge of $22 million during the second quarter of 2013. This charge represents costs associated with the COL, which are not probable of recovery. On September 16, 2013, the NCUC approved the deferral of the North Carolina retail portion of the remaining COL costs. Approximately $47 million is recorded in Regulatory assets on Duke Energy Progress' Condensed Consolidated Balance Sheet at September 30, 2013.

On April 19, 2013, Duke Energy Progress filed an application with FERC for acceptance of changes to generation depreciation rates and in August filed for acceptance of additional changes. These changes will affect the rates of DEP wholesale power customers which purchase or will purchase power under formula rates. Certain Duke Energy Progress wholesale customers filed interventions and protests. FERC accepted the depreciation rate changes, subject to refund, and set the matter for settlement and hearing in a consolidated proceeding. FERC further initiated a section 206 action with respect to the justness and reasonableness of the proposed rate changes. The parties are engaged in settlement discussions. Duke Energy Progress cannot predict the outcome of this matter.

On February 22, 2012, the FPSC approved a settlement agreement (the 2012 Settlement) among Duke Energy Florida, the Florida Office of Public Counsel (OPC) and other customer advocates. The 2012 Settlement was to continue through the last billing cycle of December 2016. The agreement addressed 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 cost recovery, and (iv) cost of removal reserve.

On October 17, 2013, the FPSC approved a settlement agreement (the 2013 Settlement) between Duke Energy Florida, OPC, and other customer advocates. The 2013 Settlement replaces and supplants the 2012 Settlement and substantially resolves 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.

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. 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, work to return the plant to service was suspended after monitoring equipment identified a new delamination. The second delamination occurred in a different section of the outer wall after 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 second 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 and 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. These initial estimates of the cost to decommission the plant resulted in an estimate in 2011 dollars of $989 million. 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 is evaluating the use of 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. An updated site specific decommissioning study will be filed with the NRC and the FPSC. Additional specifics about the decommissioning plan are being developed. The NRC requires that within two years of permanent cessation of power operations the licensee submit a Post-Shutdown Decommissioning Activities Report, which includes a description of planned decommissioning activities, schedule of significant activities, a site specific cost estimate and an environmental impact assessment. Additionally, Duke Energy Florida is developing several license amendment requests and other submittals to revise staffing, training, maintenance, emergency preparedness and security requirements in light of the permanent removal of fuel from the reactor. Duke Energy Florida anticipates filing these submissions with the NRC over the next two years.

Duke Energy Florida maintains insurance coverage through Nuclear Electric Insurance Limited's (NEIL) accidental property damage program. The NEIL coverage generally does not include property damage to or resulting from the containment structure. However, 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.

Duke Energy Florida worked with NEIL for recovery of applicable repair costs and associated replacement power costs throughout the duration of the Crystal River Unit 3 outage. On April 25, 2013 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 related to the Crystal River Unit 3 delaminations. 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 to retail customers are presented in Operating Activities on Duke Energy Florida's Condensed Statements of Cash Flows.

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.

As a result of retiring the unit, Duke Energy Florida is required to refund $100 million to retail customers through its fuel clause by the 2012 Settlement (retirement decision refund). Duke Energy Florida recorded a Regulatory liability 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. The 2012 Settlement authorized Duke Energy Florida to defer the retail portion of all Crystal River Unit 3 related costs incurred subsequent to retirement 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 operation and maintenance and property tax expenses incurred after December 31, 2013.

Duke Energy Florida agreed to forego recovery of $295 million of Crystal River Unit 3 regulatory assets in accordance with the 2013 settlement agreement. This excludes amounts related to the uprate project. Duke Energy Florida recorded a $295 million pretax charge in the second quarter of 2013 for this matter. This amount is included in Impairment charges on Duke Energy Florida's Condensed Statements of Operations and Comprehensive Income.

Duke Energy Florida is allowed to accelerate cash recovery of approximately $135 million of the Crystal River Unit 3 regulatory assets from retail customers from 2014 through 2016 through its fuel clause. Duke Energy Florida will 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 collection of the regulatory asset in base rates. 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. The return rate is 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 Nuclear Cost Recovery Clause (NCRC) over an estimated seven year period beginning in 2013.

Through September 30, 2013, Duke Energy Florida deferred $1,186 million for rate recovery related to Crystal River Unit 3, which is subject to the rate recovery cap in the 2013 settlement. In addition, Duke Energy Florida deferred $324 million for recovery costs associated with building a dry cask storage facility and the original uprate project which is not subject to the rate recovery cap discussed above. Duke Energy Florida does not expect the Crystal River Unit 3 regulatory asset to exceed the cap prior to full cash recovery from its retail customers.

The following table includes a summary of retail customer refunds agreed to in the 2012 Settlement and the 2013 Settlement

		September 30, 2013
						Remaining Amount to be Refunded
(in millions)		Total		Refunded to date		2013		2014		2015		2016
2012 Settlement refund^(a)		$	288	$	97	$	32	$	139	$	10	$	10
Retirement decision refund			100		―		―		―		40		60
NEIL proceeds			490		245		81		164		―		―
Total customer refunds		$	878		342		113		303		50		70
Accelerated regulatory asset recovery			(135)		―		―		(38)		(38)		(59)
Net customer refunds			743	$	342	$	113	$	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 this matter.

Pursuant to the 2013 Settlement, 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 is not 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. The 2012 Settlement provided for a $150 million increase in base revenue 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 earlier of the full recovery of the Levy investment or 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 2013 Settlement.

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, as required by the 2012 Settlement.

If Duke Energy Florida determines 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 greater than $8 million, the excess shall be deferred with a carrying cost and recovered through the Capacity Cost Recovery Clause beginning in January 2019.

On July 28, 2008, Duke Energy Florida applied to the NRC for a COL for two Westinghouse AP1000 reactors at Levy. 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 ruling that the NRC had carried its burden of demonstrating 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, 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 five-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. 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 updated its retail cost-recovery for Levy effective in the first billing cycle of January 2013 to the fixed rates contained in the 2012 Settlement. These recovery rates continue for a five-year period, with true-up of any actual costs not recovered during the five-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. The consumer parties agree to not oppose Duke Energy Florida continuing to pursue a COL for Levy.

Pursuant to the 2013 Settlement, Duke Energy Florida agrees to terminate the EPC at the earliest reasonable and prudent time. Duke Energy Florida is allowed to recover EPC cancellation costs from its retail customers. Duke Energy Florida will exercise its 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.

In accordance with the 2013 Settlement, Duke Energy Florida ceased 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.

Recovery of the remaining retail portion of the project costs will occur over 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 September 30, 2013, Duke Energy Florida has a net uncollected investment in Levy of approximately $265 million, including AFUDC. Of this amount, $118 million is included in Regulatory assets, $117 million related to land and the COL is included in Net, property, plant and equipment, and $30 million is included in Other within Current Assets on Duke Energy Florida's Condensed Balance Sheets.

Duke Energy Florida is evaluating Crystal River 1 and 2 coal units for retirement in order to comply with certain environmental regulations. If those units are retired Duke Energy Florida will continue recovery of 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 retirement of Crystal River Unit 3 as well as possible retirement of 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. The GBRA allows recovery of 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. On October 8, 2013, Duke Energy Florida issued a request for proposals to evaluate alternatives for an additional generation facility.

The 2012 Settlement and the 2013 Settlement provide Duke Energy Florida the discretion to reduce cost of removal amortization expense up to the balance in the cost of removal reserve until the earlier of its applicable cost of removal reserve reaches zero or the expiration of the 2013 Settlement. 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 $22 million reduction of amortization expense and a $60 million reduction in amortization expense for the three months ended September 30, 2013 and 2012, respectively. Duke Energy Florida recognized a reduction in amortization expense of $95 million and $118 million for the nine months ended September 30, 2013 and 2012, respectively. Duke Energy Florida had eligible cost of removal reserves of $19 million remaining at September 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 applied to the PUCO for the establishment of a charge for capacity provided pursuant to its obligations as a Fixed Resource Requirement (FRR) entity. The charge, which is consistent with Ohio's state compensation mechanism, is estimated to be approximately $729 million, and reflects Duke Energy Ohio's embedded cost of capacity. Hearings concluded in May 2013. Duke Energy Ohio expects an order by the end of 2013.

On May 1, 2013, the PUCO approved a settlement agreement (the Electric Settlement) related to Duke Energy Ohio's electric distribution rate case. All intervening parties signed the Electric Settlement. 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, the PUCO Staff, and intervening parties filed a settlement (the Gas Settlement) with the PUCO related to a gas distribution case. 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 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 an order by the end 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 MVP will fund 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. The project costs, including an authorized rate of return and associated operating and maintenance expenses will be 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 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 the MVP allocation methodology is consistent with cost causation principles and FERC precedent. The order further stated MISO's tariff withdrawal language establishes that once cost responsibility for transmission upgrades is determined, withdrawing transmission owners retain any costs incurred prior to their withdrawal date. In order to preserve its rights, Duke Energy Ohio appealed 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 a Schedule 39 to its tariff with the FERC. Schedule 39 provides for 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 protested the allocation of MVP costs with the FERC. On February 27, 2012, the FERC accepted Schedule 39 as a just and reasonable basis for MISO to charge MVP costs to a transmission owner that withdraws from MISO after January 1, 2012. The FERC set for hearing (i) 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 is consistent with MVP-related withdrawal obligations in the tariff at the time they withdrew from MISO, and, (ii) if not, what amount of, and methodology for calculating, any MVP cost responsibility should be.

On March 28, 2012, Duke Energy Ohio requested rehearing of FERC's 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 Schedule 39 is consistent with MVP-related withdrawal obligations in the tariff at the time Duke Energy Ohio withdrew from MISO and is otherwise just and reasonable. Under this initial decision, Duke Energy Ohio would be liable for MVP costs. Duke Energy Ohio filed 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 approved Duke Energy Kentucky's request to effect the RTO realignment, subject to several conditions. Conditions of the approval include a commitment not to seek double-recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.

On May 25, 2011 the PUCO approved a settlement between Duke Energy Ohio, Ohio Energy Group, The Office of Ohio Consumers' Counsel and the PUCO Staff related to Duke Energy Ohio's recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MTEP costs, including but not limited to MVP costs, directly or indirectly charged to Duke Energy Ohio retail customers. Duke Energy Ohio will 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. After Duke Energy Kentucky made the requested commitments, on January 25, 2011, the KPSC ruled that the approval is no longer conditional.

Upon its exit from MISO on December 31, 2011, Duke Energy Ohio recorded a liability for its exit obligation and share of MTEP costs, excluding MVP. This liability 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 granted 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 existing 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), appealed the air permit. A settlement related to the air permit was reached on August 30, 2013. The air permit was not impacted by the provisions of the settlement.

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, the IURC approved a new cost estimate for $2.35 billion (including $125 million of AFUDC). In April 2010, Duke Energy Indiana requested approval of a 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 related to the cost increase for the construction of the project including subdockets before the IURC related to the project. The Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana were parties to the settlement. This settlement agreement resolved all then pending regulatory issues related to the project. The settlement agreement, as approved, capped 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 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.

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 $600 million were recorded during the nine months ended September 30, 2012. These charges were recorded in Impairment charges and Operations, maintenance and other on Duke Energy Indiana's Condensed Consolidated Statements of Operations and Comprehensive Income.

The Joint Intervenors appealed the IURC order approving the April 2012 settlement agreement and other related regulatory orders to the Indiana Court of Appeals. 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. In these proceedings, Duke Energy Indiana requests recovery associated with the capped construction costs of the project and operating expenses for the period after the plant is in service. In September 2013, the IURC approved the tenth semi-annual IGCC rider. The eleventh semi-annual IGCC rider proceeding is pending with an order expected by April 2014.

On April 10, 2013, the IURC approved Duke Energy Indiana's plan for the addition of certain environmental pollution control projects on several of its coal-fired generating units 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).

In June 2012, the FERC 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 completion of seven other transmission projects (Long-term FERC Mitigation) and interim firm power sale agreements during the completion 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. These projects are expected to be completed no later than 2015.

On July 10, 2012, certain intervenors requested a rehearing seeking to overturn the June 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 10-20 year period, 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 certain coal-fired generating facilities in North Carolina, South Carolina, Florida, Indiana and Ohio by 2015. The facilities 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 $71 million, $187 million and $57 million, respectively, of net carrying value related to previously retired coal generation facilities included in Regulatory assets on their Condensed Consolidated Balance Sheets.


		September 30, 2013
		Duke Energy		Duke Energy Carolinas		^(b)	Progress Energy		Duke Energy Progress		^(c)(d)	Duke Energy Florida		^(e)	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)		$	319	$	14		$	171	$	59		$	112		$	10		$	124

(a)	Included in Property, plant and equipment, net as of September 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. Duke Energy Carolinas expects to retire or convert these units by December 2020 in conjunction with a settlement agreement associated with the Cliffside Unit 6 air permit.
(c)	Includes Sutton Station, which is expected to be retired by the end of 2013.
(d)	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 September 30, 2013.
(e)	Includes Crystal River Units 1 and 2.
(f)	Includes Beckjord Station Units 2 through 6 and Miami Fort Unit 6. Beckjord units have no remaining book value. Beckjord units 2 and 3 were retired effective October 1, 2013.
(g)	Includes Wabash River Units 2 through 6. Wabash River Unit 6 is being evaluated for potential conversion to gas. Duke Energy Indiana committed to retire or convert these units by June 2018 in conjunction with a settlement agreement associated with the Edwardsport air permit.

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.