The Duke Energy Registrants record regulatory assets and liabilities that result from the ratemaking process. See Note 1 for further information.

The following tables present the regulatory assets and liabilities recorded on the Consolidated Balance Sheets.


	December 31, 2013
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Accrued pension and OPEB	$	1,723	$	347	$	750	$	269	$	438	$	120	$	219
Retired generation facilities		1,748		68		1,619		241		1,378		―		61
Debt fair value adjustment		1,338		―		―		―		―		―		―
Asset retirement obligations		1,608		123		786		389		397		―		―
Net regulatory asset related to income taxes		1,115		555		331		113		218		72		157
Hedge costs and other deferrals		450		98		318		165		153		5		29
Demand side management (DSM)/Energy efficiency (EE)		371		140		152		140		12		79		―
Vacation accrual		210		82		55		50		―		7		13
Deferred fuel		94		―		37		6		31		14		43
Nuclear deferral		262		40		222		77		145		―		―
Post-in-service carrying costs and deferred operating expenses		459		150		137		19		118		21		151
Gasification services agreement buyout		75		―		―		―		―		―		75
Transmission expansion obligation		70		―		―		―		―		74		―
Manufactured gas plant (MGP)		90		―		―		―		―		90		―
Other		473		219		101		42		60		46		87
Total regulatory assets		10,086		1,822		4,508		1,511		2,950		528		835
Less: current portion		895		295		353		127		221		57		118
Total non-current regulatory assets	$	9,191	$	1,527	$	4,155	$	1,384	$	2,729	$	471	$	717


	December 31, 2013
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Liabilities
Costs of removal	$	5,308	$	2,423	$	2,008	$	1,637	$	371	$	241	$	645
Amounts to be refunded to customers		151		―		120		―		120		―		31
Storm reserve		145		20		125		―		125		―		―
Accrued pension and OPEB		138		―		―		―		―		21		77
Deferred fuel		177		45		132		―		132		―		―
Other		346		153		114		99		14		27		45
Total regulatory liabilities		6,265		2,641		2,499		1,736		762		289		798
Less: current portion		316		65		207		63		144		27		16
Total non-current regulatory liabilities	$	5,949	$	2,576	$	2,292	$	1,673	$	618	$	262	$	782


	December 31, 2012
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Accrued pension and OPEB	$	3,306	$	602		1,650	$	769	$	754	$	225	$	325
Retired generation facilities		1,781		―		1,720		128		1,592		―		61
Debt fair value adjustment		1,472		―		―		―		―		―		―
Asset retirement obligations		1,461		48		713		372		341		―		―
Net regulatory asset related to income taxes		1,373		731		401		175		226		82		158
Hedge costs and other deferrals		710		88		550		240		310		9		63
DSM/EE		322		107		121		121		―		94		―
Vacation accrual		245		85	$	65		65		―		7		13
Deferred fuel		162		―		109		―		109		1		52
Nuclear deferral		142		―		142		―		142		―		―
Post-in-service carrying costs and deferred operating expenses		122		27		―		―		―		19		76
Gasification services agreement buyout		95		―		―		―		―		―		95
Transmission expansion obligation		72		―		―		―		―		72		―
MGP		77		―		―		―		―		77		―
Other		401		260		77		52		26		39		93
Total regulatory assets		11,741		1,948		5,548		1,922		3,500		625		936
Less: current portion		737		221		256		77		179		46		126
Total non-current regulatory assets	$	11,004	$	1,727	$	5,292	$	1,845	$	3,321	$	579	$	810


	December 31, 2012
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Liabilities
Costs of removal	$	4,827	$	1,928	$	2,048	$	1,503	$	401	$	236	$	624
Amounts to be refunded to customers		290		―		259		―		259		―		31
Storm reserve		125		―		125		―		125		―		―
Accrued pension and OPEB		103		―		―		―		―		18		68
Deferred fuel		55		45		10		10		―		―		―
Other		340		207		55		35		20		39		29
Total regulatory liabilities		5,740		2,180		2,497		1,548		805		293		752
Less: current portion		156		78		28		10		18		39		11
Total non-current regulatory liabilities	$	5,584	$	2,102	$	2,469	$	1,538	$	787	$	254	$	741

Descriptions of regulatory assets and liabilities, summarized in the tables above, as well as their recovery and amortization periods follow. Items are excluded from rate base unless otherwise noted.

Accrued pension and OPEB. Accrued pension and OPEB represent regulatory assets and liabilities related to each of the Duke Energy Registrants' respective shares of unrecognized actuarial gains and losses, unrecognized prior service cost, and unrecognized transition obligation attributable to Duke Energy's pension plans and OPEB plans. The regulatory asset or liability is amortized with the recognition of actuarial gains and losses, prior service cost, and transition obligations to net periodic benefit costs for pension and OPEB plans. See Note 21 for additional detail.

Retired generation facilities. Duke Energy Florida earns a reduced return on a substantial portion of the amount of regulatory asset associated with the retirement of Crystal River Unit 3 not included in rate base and a full return on a portion of the retired plant currently recovered in rates. Once included in base rates the amount will be amortized over 20 years. Duke Energy Carolinas and Duke Energy Progress earn a return on the outstanding balance with recovery periods ranging from five to 10 years. Duke Energy Indiana earns a return on the outstanding balances and the costs are included in rate base.

Asset retirement obligations. Represents future removal costs associated with asset retirement obligations for nuclear facilities. No return is earned on these balances. The recovery period runs through the decommissioning period of each nuclear unit, the latest of which is estimated to be 2097. See Note 9 for additional information.

Net regulatory asset related to income taxes. Regulatory assets principally associated with the depreciation and recovery of AFUDC equity. Amounts have no impact on rate base as regulatory assets are offset by deferred tax liabilities. The recovery period is over the life of the associated assets.

Hedge costs and other deferrals. Amounts relate to unrealized gains and losses on derivatives recorded as a regulatory asset or liability, respectively, until the contracts are settled. The recovery period varies for these costs, and currently extends to 2027.

DSM/EE. The recovery period varies for these costs, with some currently unknown. Duke Energy Carolinas, Duke Energy Progress, and Duke Energy Florida are required to pay interest on the outstanding liability balance. Duke Energy Progress and Duke Energy Florida collect a return on the outstanding asset balance. Duke Energy Carolinas collects a return on the outstanding balance in South Carolina.

Deferred fuel. Deferred fuel costs represent certain energy costs that are recoverable or refundable as approved by the applicable regulatory body. Duke Energy Florida, Duke Energy Ohio, and Duke Energy Indiana earn a return on under-recovered costs. Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana pay interest on over-recovered costs. Duke Energy Carolinas and Duke Energy Progress pay interest on over-recovered costs in North Carolina. Recovery period is generally over one year. Duke Energy Florida amount includes capacity costs.

Nuclear deferral. Includes (i) amounts related to levelizing nuclear plant outage costs at Duke Energy Carolinas in North Carolina and South Carolina, and Duke Energy Progress in North Carolina, which allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, resulting in the deferral of operations and maintenance costs associated with refueling and (ii) certain deferred preconstruction and carrying costs at Duke Energy Florida as approved by the FPSC associated with Levy, expected to be recovered in revenues by the end of 2017.

Post-in-service carrying costs and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service. Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana earn a return on the outstanding balance. Duke Energy Ohio amounts are included in rate base. For Duke Energy Indiana, some amounts are included in rate base. Recovery is over various lives, and the latest recovery period is 2067.

Gasification services agreement buyout. The IURC authorized Duke Energy Indiana to recover costs incurred to buyout a gasification services agreement, including carrying costs through 2018.

Transmission expansion obligation. Represents transmission expansion obligations related to Duke Energy Ohio's withdrawal from Midcontinent Independent System Operator, Inc. (MISO).

MGP. Represents remediation costs for former MGP sites. In November 2013, the PUCO approved recovery of these costs through 2018. Duke Energy Ohio does not earn a return on these costs. See Note 5, Commitments and Contingencies, for additional information.

Debt fair value adjustment. Purchase accounting adjustment to restate the carrying value of Progress Energy debt to fair value. Amount is amortized over the life of the related debt.

Costs of removal. Represents funds received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites as property is retired. Also includes unrealized gains on NDTF investments.

Amounts to be refunded to customers. Represents required refunds to retail customers by the applicable regulatory body. The refund period is through 2016 for Duke Energy Florida and through 2017 for Duke Energy Indiana.

Storm reserve. Duke Energy Carolinas and Duke Energy Florida are allowed to petition the PSCSC and FPSC, respectively, to seek recovery of named storms. Funds are used to offset future incurred costs.

Restrictions on the Ability of Certain Subsidiaries to Make Dividends, Advances and Loans to Duke Energy

As a condition to the approval of merger transactions, the NCUC, PSCSC, PUCO, KPSC, and IURC imposed conditions on the ability of Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio, Duke Energy Kentucky and Duke Energy Indiana to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy. Certain subsidiaries may transfer funds to the parent by obtaining approval of the respective state regulatory commissions. These conditions imposed restrictions on the ability of the public utility subsidiaries to pay cash dividends as discussed below.

Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures and Articles of Incorporation which, in certain circumstances, limited their ability to make cash dividends or distributions on common stock. Amounts restricted as a result of these provisions were not material at December 31, 2013.

Additionally, certain other subsidiaries of Duke Energy have restrictions on their ability to dividend, loan or advance funds to Duke Energy due to specific legal or regulatory restrictions, including, but not limited to, minimum working capital and tangible net worth requirements.

Duke Energy Carolinas must limit cumulative distributions subsequent to mergers to (i) the amount of retained earnings on the day prior to the closing of the mergers, plus (ii) any future earnings recorded.

Duke Energy Progress must limit cumulative distributions subsequent to the merger between Duke Energy and Progress Energy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded.

Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. Duke Energy Ohio received FERC and PUCO approval to pay dividends from its equity accounts that are reflective of the amount that it would have in its retained earnings account had push-down accounting for the Cinergy Corp. (Cinergy) merger not been applied to Duke Energy Ohio's balance sheet. The conditions include a commitment from Duke Energy Ohio that equity, adjusted to remove the impacts of push-down accounting, will not fall below 30 percent of total capital.

Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35 percent equity in its capital structure.

Duke Energy Indiana must limit cumulative distributions subsequent to the merger between Duke Energy and Cinergy to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded. In addition, Duke Energy Indiana will not declare and pay dividends out of capital or unearned surplus without prior authorization of the IURC.

The restrictions discussed above were less than 25 percent of Duke Energy's net assets at December 31, 2013.

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 (excluding Ohio and Indiana), 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 agreed to a three-year step-in rate increase, with the first two years providing for $204 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. On December 11, 2013, Duke Energy Carolinas and Duke Energy Progress, along with the Public Staff, filed a Motion to Consolidate this appeal with other North Carolina rate case appeals involving Duke Energy Carolinas and Duke Energy Progress. Both the NCAG and NC WARN filed responses with the North Carolina Supreme Court (NCSC) contesting consolidation. All parties are awaiting a ruling from the NCSC. 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 October 23, 2013, the NCUC reaffirmed the rate of return approved in the January 27, 2012 settlement agreement, in response to an appeal by the NCAG. On November 21, 2013, the NCAG appealed the reaffirmed order. On December 11, 2013, Duke Energy Carolinas and Duke Energy Progress, along with the Public Staff, filed a Motion to Consolidate this appeal with other North Carolina rate case appeals involving Duke Energy Carolinas and Duke Energy Progress. Both the NCAG and NC WARN filed responses with the NCSC contesting consolidation. All parties are awaiting a ruling from the NCSC. Duke Energy Carolinas cannot predict the outcome of this matter.

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 did not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC 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 $382 million, including AFUDC through December 31, 2013. This amount is included in Net property, plant and equipment on Duke Energy Carolinas' 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 November 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.

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 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 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 shareholder 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. NC WARN also appealed various matters in the settlement. On December 11, 2013, Duke Energy Carolinas and Duke Energy Progress, along with the Public Staff, filed a Motion to Consolidate this appeal with other North Carolina rate case appeals involving Duke Energy Carolinas and Duke Energy Progress. Both the NCAG and NC WARN filed responses with the NCSC contesting consolidation. All parties are awaiting a ruling from the NCSC. Duke Energy Progress cannot predict the outcome of this matter.

Duke Energy Progress completed construction of a 625 MW combined cycle natural gas-fired generating facility at its existing Sutton Steam Station in New Hanover County, North Carolina. Sutton began commercial operations 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 and January 30, 2014, respectively, the NCUC and PSCSC approved the deferral of the respective retail portion of the COL costs. Approximately $47 million is recorded in Regulatory assets on Duke Energy Progress' Consolidated Balance Sheets at December 31, 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 Duke Energy Progress wholesale power customers that 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 an action with respect to the justness and reasonableness of the proposed rate changes. 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 it did not have a high degree of confidence the 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. In December 2013, Duke Energy Florida filed an updated site-specific decommissioning study and plan with the NRC and FPSC. The study resulted in a decommissioning cost estimate of $1,180 million, including amounts applicable to joint owners, under the safe storage (SAFSTOR) option. Duke Energy Florida's decommissioning study assumes Crystal River Unit 3 will be in SAFSTOR configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur in 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.

Duke Energy Florida maintains insurance coverage through Nuclear Electric Insurance Limited's (NEIL) accidental property damage program on an actual cash value basis. The NEIL coverage generally does not include property damage to or resulting from the containment structure. However, 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 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; the uprate project; and the components of the regulatory asset to be recovered in rates beginning no later than 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 in accordance with 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, payroll taxes, property taxes, and depreciation associated with Crystal River Unit 3 were deferred to a regulatory asset. Duke Energy Florida deferred $134 million of these costs to Regulatory assets through December 31, 2013. 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. 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 Statements of Operations and Comprehensive Income.

Duke Energy Florida is allowed to accelerate cash recovery of approximately $130 million of the Crystal River Unit 3 regulatory asset 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. 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 December 31, 2013, Duke Energy Florida deferred $1,310 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 $323 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.


		December 31, 2013
							Remaining Amount to be Refunded
(in millions)		Total		Refunded to date		2014		2015		2016
2012 Settlement refund^(a)		$	288	$	129	$	139	$	10	$	10
Retirement decision refund			100		-		-		40		60
NEIL proceeds			490		326		164		-		-
Total customer refunds			878		455		303		50		70
Accelerated regulatory asset recovery			(130)		-		(37)		(37)		(56)
Net customer refunds		$	748	$	455	$	266	$	13	$	14

(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 joint owner and extended a settlement offer to the other joint owner related to all Crystal River Unit 3 matters. Duke Energy Florida recorded a charge of $45 million in the fourth quarter of 2012 related to the December 2012 settlement and settlement offer. In January 2014, Duke Energy Florida reached an agreement in principle with the remaining joint owner regarding resolution of matters associated with Crystal River Unit 3 based on condition precedents that must be met in order to carry out the agreement. Duke Energy Florida recorded a charge of $57 million in the fourth quarter of 2013 related to the January 2014 agreement. The significant majority of these amounts were included in Operations, maintenance and other on the Statements of Operations and Comprehensive Income.

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, with exceptions for base rate increases for the recovery of the Crystal River Unit 3 regulatory asset beginning no later than 2017 and base rate increases for new generation through 2018, per the provisions of the 2013 Settlement. 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. 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 monthly earnings surveillance report, it may petition the FPSC to amend its base rates during the term of the 2013 Settlement.

Duke Energy Florida is refunding $288 million to retail customers through its fuel clause, as required by the 2012 Settlement.

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.

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 including 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. The consumer parties agree to not oppose Duke Energy Florida continuing to pursue a COL for Levy.

On January 28, 2014, Duke Energy Florida terminated the EPC. Duke Energy Florida may be required to pay for work performed under the EPC and to bring existing work to an orderly conclusion, including but not limited to, costs to demobilize and cancel certain equipment and material orders placed. Duke Energy Florida is allowed to recover reasonable and prudent EPC cancellation costs from its retail customers. 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 the 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 December 31, 2013, Duke Energy Florida has a net uncollected investment in Levy of approximately $264 million, including AFUDC. Of this amount, $50 million is included in Regulatory assets, $117 million related to land and the COL is included in Net, property, plant and equipment, and $97 million is included in Regulatory assets within Current Assets on the Balance Sheets.

Duke Energy Florida has evaluated Crystal River 1 and 2 coal units for retirement in order to comply with certain environmental regulations. Based on this evaluation, those units will likely be retired by 2018. Once 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. On December 31, 2013 Duke Energy Florida filed a petition with the FPSC to allow for the recovery of prudently incurred costs to comply with the Mercury and Air Toxics Standard through the Environmental Cost Recovery Clause.

Duke Energy Florida currently projects a significant need for additional generation to offset the impact of retirement of Crystal River Unit 3 as well as the 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. Duke Energy Florida is currently reviewing bids received on December 9, 2013.

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 reduction in amortization expense of $114 million, $178 million, and $250 million for the years ended December 31, 2013, 2012, and 2011 respectively. Duke Energy Florida had no cost of removal reserves eligible for amortization to income remaining at December 31, 2013

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. On February 13, 2014, the PUCO denied Duke Energy Ohio's request.

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.

On November 13, 2013, the PUCO issued an order approving the Gas Settlement and allowing for the recovery of $56 million of MGP costs, excluding carrying costs, to be recovered over a five-year period beginning in 2014. On February 19, 2014, the PUCO denied intervening consumer groups' motion to stay implementation of its order, or, in the alternative, to implement the MGP rider subject to refund. Intervening groups have provided notice of their intent to appeal the PUCO's decision to the Ohio Supreme Court. Duke Energy Ohio cannot predict the outcome of this matter.

On April 2, 2012 and amended on June 22, 2012, Duke Energy Ohio and various affiliated entities filed an Application for Authorization for Disposition of Jurisdictional Facilities with FERC. The application seeks to transfer, from Duke Energy Ohio's rate-regulated Ohio utility company, the legacy coal-fired and combustion gas turbine assets to a nonregulated affiliate, consistent with the ESP stipulation approved by the PUCO on November 22, 2011. The application outlines a potential additional step in the reorganization that would result in a transfer of all of Duke Energy Ohio's Commercial Power business to an indirect wholly owned subsidiary of Duke Energy. The process of determining the optimal corporate structure is an ongoing evaluation of factors, such as tax considerations, that may change between now and the transfer date. In conjunction with the transfer, Duke Energy Ohio's capital structure will be restructured to reflect appropriate debt and equity ratios for its regulated operations. The transfer could instead be accomplished within a wholly owned nonregulated subsidiary of Duke Energy Ohio depending on final tax structuring analysis. The FERC approved the application on September 5, 2012. Duke Energy Ohio agreed to transfer the legacy coal-fired and combustion gas turbine assets on or before December 31, 2014.

Duke Energy Ohio including Duke Energy Kentucky, transferred control of its transmission assets from MISO to PJM, effective December 31, 2011.

On December 22, 2010, the KPSC approved Duke Energy Kentucky's request to effect the RTO realignment, subject to 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 MISO Transmission Expansion Project (MTEP) costs, including but not limited to Multi-Value Project (MVP) costs, directly or indirectly charged to Duke Energy Ohio retail customers. Duke Energy Ohio will not 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.

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 Consolidated Balance Sheets.

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.

MVP. MISO approved 17 MVP proposals prior to Duke Energy Ohio's exit from MISO on December 31, 2011. Construction of these projects is expected to continue through 2020. Costs of these projects, including operating and maintenance costs, property and income taxes, depreciation and an allowed return, are allocated and billed to MISO transmission owners.

On December 29, 2011, MISO filed a tariff with the FERC providing for the allocation of MVP costs to a withdrawing owner based on monthly energy usage. The FERC set for hearing (i) whether MISO's proposed cost allocation methodology to transmission owners who withdrew from MISO prior to January 1, 2012 is consistent with the tariff at the time of their withdrawal from MISO, and, (ii) if not, what amount of, and methodology for calculating any MVP cost responsibility should be. On July 16, 2013, a FERC Administrative Law Judge (ALJ) issued an initial decision. 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 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. Duke Energy Ohio cannot predict the outcome of these proceedings.

In 2012, MISO estimated Duke Energy Ohio's MVP obligation over the period from 2012 to 2071 at $2.7 billion, on an undiscounted basis. The estimated obligation is subject to great uncertainty including the ultimate cost of the projects, the annual costs of O&M, taxes and return over the project lives and the allocation to Duke Energy Ohio.

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., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc., 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. As a result, the projected cost estimate increased throughout construction of the project and various revised estimates were filed with the IURC. In October 2012, Duke Energy Indiana revised its latest projected cost estimate to $3.15 billion (excluding AFUDC).

On December 27, 2012, the IURC approved a settlement agreement (2012 Edwardsport settlement) 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 2012 Edwardsport settlement 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 pretax charges of approximately $897 million related to the Edwardsport project, including the settlement agreement discussed above. Of this amount, pretax impairment and other charges of $631 million were recorded during the year ended December 31, 2012. These charges were recorded in Impairment charges and Operations, maintenance and other on Duke Energy Indiana's Consolidated Statements of Operations and Comprehensive Income.

The Joint Intervenors appealed the IURC order approving the 2012 Edwardsport settlement and other related regulatory orders to the Indiana Court of Appeals. A final decision is anticipated mid-2014.

The project was placed in commercial operation in June 2013. Costs for the Edwardsport IGCC plant are recovered from retail electric customers via a tracking mechanism, the IGCC Rider.

On January 9, 2013, the City of Orangeburg and NC WARN appealed the NCUC's approval of the merger between Duke Energy and Progress Energy. On April 29, 2013, the NCUC granted Duke Energy's motion to dismiss certain exceptions contained in NC WARN's appeal. On November 6, 2013, the North Carolina Court of Appeals heard oral arguments on the appeals. A decision from the North Carolina Court of Appeals is pending.

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. 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 in 2014. On August 8, 2012, FERC granted certain intervenors' request for rehearing for further consideration.

Following the closing of the merger, outside counsel reviewed Duke Energy's mitigation plan and discovered a technical error in the calculations. On December 6, 2013, Duke Energy submitted a filing with the FERC disclosing the error and arguing that no additional mitigation is necessary. On February 4, 2014, The City of New Bern, North Carolina filed comments to Duke Energy's filing. Duke Energy's response to New Bern was filed on February 19, 2014. 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 IRPs filed by the Subsidiary Registrants in 2013, 2012 and 2011 included planning assumptions to potentially retire certain coal-fired generating facilities in South Carolina, Florida, Indiana and Ohio earlier than their current estimated useful lives. The facilities do not have the requisite emission control equipment, primarily to meet 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 Consolidated Balance Sheets.


		December 31, 2013
			Duke Energy	Duke Energy Carolinas^(b)		Progress Energy^(c)		Duke Energy Florida^(c)		Duke Energy Ohio^(d)		Duke Energy Indiana^(e)
Capacity (in MW)			2,447		200		873		873		706		668
Remaining net book value (in millions)^(a)		$	260	$	14	$	113	$	113	$	10	$	123

(a)	Included in Property, plant and equipment, net as of December 31, 2013, on the Consolidated Balance Sheets.
(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 Crystal River Units 1 and 2.
(d)	Includes Beckjord Units 4 through 6 and Miami Fort Unit 6. 150 MW Beckjord Station Unit 4 was retired on February 17, 2014. Beckjord units have no remaining book value.
(e)	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.