As of December 31, 2012 and 2011, the substantial majority of USFE&G's operations applied regulatory accounting treatment. Accordingly, these businesses record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further information.

The following tables represent the regulatory assets and liabilities on the Duke Energy Registrant's Consolidated Balance Sheets:

	As of December 31, 2012
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Progress Energy Carolinas		Progress Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Vacation accrual	$	245	$	85	$	65	$	65	$	-	$	7	$	13
Nuclear deferral		65		-		65		-		65		-		-
Demand side management (DSM) costs/Energy efficiency (EE)		58		36		-		-		-		22		-
Deferred fuel costs		162		-		109		-		109		1		52
Over-distribution of Bulk Power Marketing (BPM) sharing		43		43		-		-		-		-		-
Post in-service carrying costs and deferred operating expenses		29		27		-		-		-		-		2
Gasification services agreement buyout costs		25		-		-		-		-		-		25
Other		110		30		17		12		5		16		34
Total Current Regulatory Assets^(a)		737		221		256		77		179		46		126
Accrued pension and post-retirement		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 costs/Energy efficiency		264		71		121		121		-		72		-
Post in-service carrying costs and deferred operating expenses		93		-		-		-		-		19		74
Regional Transmission Organization (RTO) costs		83		10		5		5		-		72		-
Manufactured gas plant (MGP) costs		77		-		-		-		-		77		-
Gasification services agreement buyout costs		70		-		-		-		-		-		70
Nuclear deferral		77		-		77		-		77		-		-
Other		237		177		55		35		21		23		59
Total Non-Current Regulatory Assets		11,004		1,727		5,292		1,845		3,321		579		810
Total Regulatory Assets	$	11,741	$	1,948	$	5,548	$	1,922	$	3,500	$	625	$	936

	As of December 31, 2012
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Progress Energy Carolinas		Progress Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Liabilities
Deferred fuel costs	$	55	$	45	$	10	$	10	$	-	$	-	$	-
DSM costs/Energy efficiency		49		9		17		-		17		15		8
Other		52		24		1		-		1		24		3
Total Current Regulatory Liabilities^(b)		156		78		28		10		18		39		11
Removal costs		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 post-retirement benefits		103		-		-		-		-		18		68
Other		239		174		37		35		2		-		18
Total Non-Current Regulatory Liabilities		5,584		2,102		2,469		1,538		787		254		741
Total Regulatory Liabilities	$	5,740	$	2,180	$	2,497	$	1,548	$	805	$	293	$	752

	As of December 31, 2011
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Progress Energy Carolinas		Progress Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Vacation accrual	$	150	$	70	$	-	$	-	$	-	$	7	$	13
DSM costs/Energy efficiency		52		25		-		-		-		9		18
Over-distribution of BPM sharing		41		41		-		-		-		-		-
Deferred fuel costs		38		-		275		31		244		10		28
Post in-service carrying costs and deferred operating expenses		31		28		-		-		-		-		3
Gasification services agreement buyout costs		25		-		-		-		-		-		25
Other		37		8		-		-		-		2		27
Total Current Regulatory Assets^(a)		374		172		275		31		244		28		114
Accrued pension and post-retirement		1,726		734		1,506		691		702		212		314
Net regulatory asset related to income taxes		892		668		352		140		212		77		147
Asset retirement obligations		191		191		540		496		44		-		-
Hedge costs and other deferrals		166		91		703		200		503		8		67
Post in-service carrying costs and deferred operating expenses		119		31		-		-		-		16		72
Nuclear deferral		-		-		129		-		129		-		-
Gasification services agreement buyout costs		88		-		-		-		-		-		88
RTO costs		80		13		7		7		-		74		-
Retired generation facilities		73		-		15		15		-		-		73
MGP costs		69		-		-		-		-		69		-
DSM costs/Energy efficiency		70		38		92		92		-		32		-
Other		198		128		80		41		39		32		37
Total Non-Current Regulatory Assets		3,672		1,894		3,424		1,682		1,629		520		798
Total Regulatory Assets	$	4,046	$	2,066	$	3,699	$	1,713	$	1,873	$	548	$	912

		As of December 31, 2011
(in millions)		Duke Energy		Duke Energy Carolinas		Progress Energy		Progress Energy Carolinas		Progress Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Liabilities
DSM costs/Energy efficiency		$	41	$	41	$	19	$	-	$	19	$	-	$	-
Nuclear deferral			-		-		15		-		15		-		-
Other			46		21		14		2		12		22		3
Total Current Regulatory Liabilities^(b)			87		62		48		2		46		22		3
Removal costs			2,586		1,770		2,240		1,529		550		230		590
Accrued pension and post-retirement benefits			117		-		-		-		-		19		70
Amount to be refunded to customers			-		-		288		-		288		-		-
Storm reserve			-		-		135		-		135		-		-
Other			216		158		64		14		51		24		23
Total Non-Current Regulatory Liabilities			2,919		1,928		2,727		1,543		1,024		273		683
Total Regulatory Liabilities		$	3,006	$	1,990	$	2,775	$	1,545	$	1,070	$	295	$	686

(a)	Included in Other within Current Assets on the Consolidated Balance Sheets.
(b)	Included in Other within Current Liabilities on the Consolidated Balance Sheets.

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

Vacation accrual. Vacation is accrued as it is earned by employees and generally recovered as it is paid, generally within one year. This includes both accrued vacation and personal holiday pay.

Nuclear deferral. In 2009, pursuant to the FPSC nuclear cost-recovery rule, Progress Energy Florida filed a petition to recover costs, which primarily consisted of preconstruction and carrying costs incurred or anticipated to be incurred during 2009 and the projected 2010 costs associated with the Levy project. In an effort to help mitigate the initial price impact on its customers, as part of its filing, Progress Energy Florida recorded this asset, and it was to be recovered or amortized, as approved by the FPSC, over a period not exceeding five years. These costs are projected to be recovered by the end of 2014. This amount also includes deferred depreciation expense related to Crystal River Unit 3 as a result of the 2012 FPSC settlement agreement.

DSM Costs/EE. These amounts represent costs recoverable or refundable under the Duke Energy Registrants' Demand Side Management programs, various state Energy Efficiency programs, SmartGrid, and other peak time energy management programs. The recovery period varies for these costs, with some currently unknown. Duke Energy Carolinas and Progress Energy Florida are required to pay interest on the outstanding liability balance, and Progress Energy Florida collects interest on the outstanding asset balance.

Deferred fuel costs. Deferred fuel costs represent certain energy costs that are recoverable or refundable as approved by the applicable regulatory body. Interest is earned on under-recovered costs and interest is paid on over-recovered costs to customers.

For Progress Energy Florida, as a result of the 2012 FPSC settlement agreement, the FPSC approved an agreement between Progress Energy Florida and consumer advocates in Florida that provides customers a refund through the fuel clause, relating to the Crystal River Unit 3 delamination and subsequent outage. The amounts for Progress Energy Florida are reduced by this refund.

Over-distribution of BPM sharing. These costs represent Duke Energy Carolinas' BPM sharing requirements by the NCUC. The NCUC requires a percentage of the profits on the wholesale market to be shared with retail customers. Under the BPM rider, Duke Energy Carolinas is required to true-up any differences, and as a result, the over-distribution to retail customers is recorded as a regulatory asset. The recovery period for these costs is generally one year, and Duke Energy Carolinas earns a return on the balance.

Post-in-service carrying costs and deferred operating expenses. These costs represent deferred depreciation and operating expenses as well as carrying costs on the portion of assets of the Duke Energy Registrants' capital expenditure programs that are placed in service but not yet reflected in rates as plant in service. Duke Energy Carolinas is allowed to earn a return on the North Carolina portion of the outstanding balance, but does not earn a return on the South Carolina portion. Duke Energy Ohio and Duke Energy Indiana are allowed to earn a return on the outstanding balance. Duke Energy Carolinas amounts are excluded from rate base and Duke Energy Ohio amounts are included in rate base. At Duke Energy Indiana, some amounts are included in and some are excluded from rate base. Recovery is over various lives, and the latest recovery period for these costs is 2067.

Gasification services agreement buyout costs. In 1999, Duke Energy Indiana entered into a buyout of a gasification services agreement. The IURC authorized Duke Energy Indiana to recover costs incurred, including carrying costs on the unrecovered balance, over an 18-year period. Duke Energy Indiana earns a return on the balance, and the recovery period lasts through 2018.

Accrued pension and post-retirement. Accrued pension and other post-retirement benefits represent regulatory assets related to the recognition of each of the Duke Energy Registrants' respective shares of the underfunded status of Duke Energy and Progress Energy's defined benefit and other post-retirement plans as a liability on each registrant's balance sheet. The regulatory asset is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses attributable to Duke Energy and Progress Energy's pension plans and other post-retirement benefit plans determined by the cost recognition provisions of the accounting guidance for pensions and post-retirement benefits. See Note 23, Employee Benefit Plans, for additional detail.

Retired generation facilities. These amounts represent the net book value of Duke Energy facilities that have been retired. Duke Energy Indiana earns a return on the outstanding balances and the costs are included in rate base. Progress Energy Carolinas anticipates earning a return on the outstanding balance with the costs excluded from rate base. For Duke Energy Indiana, the recovery period is through 2026. For Progress Energy Carolinas, the recovery period is over the previously estimated lives of the units.

Debt fair value adjustment. These costs represent purchase accounting adjustments as a result of the merger with Progress Energy in July 2012 to restate the carrying value of existing debt to fair value. The increase in the carrying value of the debt is due to a general reduction in interest rates since the underlying debt was issued. Since the debt is reflected in capital structure for rate setting purposes at its original carrying value and interest rate, the increase in the carrying value of the debt is recorded to a regulatory asset.

Asset retirement obligations. These costs represent future removal costs associated with the Duke Energy Registrants' existing asset retirement obligations. The Duke Energy Registrants do not earn a return on these balances. The recovery period trends with the expiration of the COL for each nuclear unit, the latest of which is 2043. See Note 9, Asset Retirement Obligations, for additional information.

Net regulatory asset related to income taxes. These costs represent the difference between the regulatory accounting of income taxes and the GAAP accounting of income taxes. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the accounting guidance for certain types of regulation and income taxes, include the deferred tax effects associated principally with depreciation of AFUDC equity accounted for in accordance with the ratemaking policies of the respective regulatory bodies, as well as the revenue impacts, and assume continued recovery of these costs in future transmission and distribution rates. A portion of these costs are included in rate base as a reduction of deferred income taxes and the recovery period is over the life of the associated assets.

Hedge costs and other deferrals. These costs are related to unrealized gains and losses on derivatives that are recorded as a regulatory asset or liability, respectively, until the contracts are settled. The recovery period varies for these costs, with some currently unknown.

RTO costs. Duke Energy Carolinas and Progress Energy Carolinas RTO costs reflect those from GridSouth, while those from Duke Energy Ohio and Duke Energy Indiana are related to the Midwest Independent Transmission System Operator, Inc. (MISO). These amounts reduce rate base and the liability for the removal costs is extinguished as the related removal costs are incurred.

MGP costs. These costs represent remediation costs for Duke Energy Ohio's former MGP sites. Duke Energy Ohio has requested recovery of these costs in its currently pending gas distribution rate case. If the costs are deemed to be recoverable through rates, the period of recovery will be related to the timing of the actual cleanup expenditures and is unknown at this time. Duke Energy Ohio does not earn a return on these costs. See Note 5, Commitments and Contingencies, for additional information.

Removal costs. These amounts represent funds the Duke Energy Registrants have received from customers to cover the future removal of property, plant and equipment from retired or abandoned sites which reduces rate base for ratemaking purposes. These costs are included in rate base, and the liability for removal costs is extinguished over the life of the associated asset.

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

Storm reserve. Progress Energy Florida is allowed to petition the FPSC to seek recovery of named storms under the 2012 FPSC settlement agreement. Recovery from customers will begin, subject the FPSC approval, 60 days following the filing of a cost recovery petition and will be based on a 12-month recovery period.

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

As a condition to the Duke Energy and Cinergy Corp. (Cinergy) merger approval, the NCUC, the PSCSC, the PUCO, the KPSC, and the IURC imposed conditions (the Cinergy Merger Conditions) on the ability of Duke Energy Carolinas, 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. As a condition to the Duke Energy and Progress Energy merger approval, the NCUC and the PSCSC imposed conditions (the Progress Merger Conditions) on the ability of Duke Energy Carolinas, and Progress Energy Carolinas to transfer funds to Duke Energy through loans or advances, as well as restricted amounts available to pay dividends to Duke Energy.

Duke Energy's public utility subsidiaries may not transfer funds to the parent through intercompany loans or advances; however, 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.

Progress Energy Carolinas and Progress 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, 2012.

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.

Under both the Cinergy Merger Conditions and Progress Merger Conditions, Duke Energy Carolinas must limit cumulative distributions to Duke Energy subsequent to the merger to (i) the amount of retained earnings on the day prior to the closing of the merger, plus (ii) any future earnings recorded by Duke Energy Carolinas subsequent to the merger.

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

Under the Cinergy Merger Conditions, Duke Energy Ohio will not declare and pay dividends out of capital or unearned surplus without the prior authorization of the PUCO. In November 2011, the FERC approved, with conditions, Duke Energy Ohio's request 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 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% of total capital. In January 2012, the PUCO issued an order approving the payment of dividends in a manner consistent with the method approved in the November 2011 FERC order. Under the Merger Conditions, Duke Energy Kentucky is required to pay dividends solely out of retained earnings and to maintain a minimum of 35% equity in its capital structure.

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

The following table includes information regarding the Subsidiary Registrants and other Duke Energy subsidiaries' restricted net assets at December 31, 2012.

(in billions)		Total Duke Energy Subsidiaries		Duke Energy Carolinas		Progress Energy		Progress Energy Carolinas		Duke Energy Ohio^(a)		Duke Energy Indiana
Amounts that may not be transferred to Duke Energy without appropriate approval based on above mentioned Merger Conditions		$	10.3	$	2.8	$	2.0	$	1.9	$	3.9	$	1.4

(a)	As of December 31, 2012, the equity balance available for payment of dividends, based on the FERC and PUCO order discussed above, was $1.3 billion.

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.

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

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

2011 North Carolina Rate Case. On January 27, 2012, the NCUC approved a settlement agreement between Duke Energy Carolinas and the North Carolina Utilities Public Staff (Public Staff). The terms of the agreement include an average 7.2% increase in retail revenues, or approximately $309 million annually beginning in February 2012. The agreement includes a 10.5% return on equity and a capital structure of 53% equity and 47% long-term debt.

On March 28, 2012, the North Carolina Attorney General filed a notice of appeal with the NCUC challenging the rate of return approved in the agreement. On April 17, 2012, the NCUC denied Duke Energy Carolinas' request to dismiss the notice of appeal. Briefs were filed on August 22, 2012 by the North Carolina Attorney General and the AARP with the North Carolina Supreme Court, which is hearing the appeal. Duke Energy Carolinas filed a motion to dismiss the appeal on August 31, 2012 and the North Carolina Attorney General filed a response to that motion on September 13, 2012. Briefs by the appellees, Duke Energy Carolinas and the Public Staff, were filed on September 21, 2012. The North Carolina Supreme Court denied Duke Energy Carolinas' motion to dismiss on procedural grounds and oral arguments were held on November 13, 2012. Duke Energy Carolinas is awaiting an order.

2011 South Carolina Rate Case. On January 25, 2012, the PSCSC approved a settlement agreement between Duke Energy Carolinas and the ORS, Wal-Mart Stores East, LP, and Sam's East, Inc. The Commission of Public Works for the city of Spartanburg, South Carolina and the Spartanburg Sanitary Sewer District were not parties to the agreement; however, they did not object to the agreement. The terms of the agreement include an average 5.98% increase in retail and commercial revenues, or approximately $93 million annually beginning February 6, 2012. The agreement includes a 10.5% return on equity, a capital structure of 53% equity and 47% long-term debt.

Cliffside Unit 6. On March 21, 2007, the NCUC issued an order allowing Duke Energy Carolinas to build an 800 MW coal-fired unit. Following final equipment selection and the completion of detailed engineering, Cliffside Unit 6 has a net output of 825 MW. On January 31, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding AFUDC of $600 million) for Cliffside Unit 6. In March 2010, Duke Energy Carolinas filed an update to the cost estimate of $1.8 billion (excluding AFUDC) with the NCUC where it reduced the estimated AFUDC financing costs to $400 million as a result of the December 2009 rate case settlement with the NCUC that allowed the inclusion of construction work in progress in rate base prospectively. Cliffside Unit 6 began commercial operation in the fourth quarter of 2012.

Dan River Combined Cycle Facility. In June 2008, the NCUC issued its order approving the Certificate of Public Convenience and Necessity (CPCN) applications to construct a 620 MW combined cycle natural gas fired generating facility at Duke Energy Carolinas' existing Dan River Steam Station. The Division of Air Quality (DAQ) issued a final air permit authorizing construction of the Dan River combined cycle natural gas-fired generating unit in August 2009. Dan River began commercial operation in the fourth quarter of 2012.

William States Lee III Nuclear Station. In December 2007, Duke Energy Carolinas filed an application with the NRC, which has been docketed for review, for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station (Lee Nuclear Station) at a site in Cherokee County, South Carolina. Each reactor is capable of producing 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC have concurred with the prudency of Duke Energy incurring project development and pre-construction costs.

V.C. Summer Nuclear Station Letter of Intent. 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% to 10% ownership interest in the V.C. Summer Nuclear Station being developed by Santee Cooper and SCE&G near Jenkinsville, South Carolina. The letter of intent provides a path for Duke Energy Carolinas to conduct the necessary due diligence to determine if future participation in this project is beneficial for its customers. On November 7, 2012, the term of the letter of intent expired, though Duke Energy Carolinas remains engaged in discussions at this time.

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

On February 25, 2013, the North Carolina Public Staff filed with the NCUC a Notice of Settlement in Principle (Settlement Notice). Pursuant to the Settlement Notice between Progress Energy Carolinas and the Public Staff, the parties have agreed to a two year step-in to a total agreed upon net rate increase, with the first year providing for a $151 million, or 4.7% average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or 1.0% average increase in rates. This second year increase is a result of Progress Energy Carolinas agreeing to delay collection of financing costs on the construction work in progress for the Sutton combined cycle natural gas plant for one year. The Settlement Notice is based upon a return on equity of 10.2% and a 53% equity component of the capital structure.

Once filed, the actual settlement agreement will be subject to approval by the NCUC. Progress Energy Carolinas expects revised rates, if approved, to go into effect June 1, 2013.

HF Lee and L.V. Sutton Combined Cycle Facilities. Progress Energy Carolinas has been constructing two new generating facilities, which consist of an approximately 920 MW combined cycle natural gas-fired generating facility at the HF Lee Energy Complex (Lee) in Wayne County, North Carolina, and an approximately 625 MW natural gas-fired generating facility at its existing L.V. Sutton Steam Station (Sutton) in New Hanover County, North Carolina. The Lee project began commercial operation in the fourth quarter of 2012. Total estimated costs at final project completion (including AFUDC) for the Sutton project, which is approximately 64% complete, are $600 million. Sutton is expected to be in service in the fourth quarter of 2013.

Shearon Harris Nuclear Station Expansion. In 2006, Progress Energy Carolinas selected a site at its existing Shearon Harris Nuclear Station (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, Progress Energy Carolinas filed its COL application with the NRC for two Westinghouse Electric AP1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

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

Crystal River Unit 3. In September 2009, Crystal River Unit 3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, it was determined that the concrete delamination at Crystal River Unit 3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created to accommodate the replacement of the unit's steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. Crystal River Unit 3 has remained out of service while Progress Energy Florida conducted an engineering analysis and review of the new delamination and evaluated possible repair options.

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

Progress Energy Florida developed a repair plan, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls, which had a preliminary cost estimate of $900 million to $1.3 billion.

In March 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the Progress Energy Florida Crystal River Unit 3 repair plan, including the repair scope, risks, costs and schedule. In its final report in late September, Zapata found that the proposed repair scope appears to be technically feasible, but there were significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair Crystal River Unit 3, including; (i) an independent review of the proposed repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of Progress Energy Florida's previous bid information, which included cost estimate data from Progress Energy Florida, of which Zapata estimated costs of $1.55 billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the Progress Energy Florida scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming Progress Energy Florida performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months. The principal difference between Zapata's estimate and Progress Energy Florida's previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. Progress Energy Florida has filed a copy of the Zapata report with the FPSC and with the NRC. The FPSC held a status conference on October 30, 2012 to discuss Duke Energy's analysis of the Zapata report.

On February 5, 2013, following the completion of a comprehensive analysis, Duke Energy announced its intention to retire Crystal River Unit 3. Duke Energy concluded that it did not have a high degree of confidence that repair could be successfully completed and licensed within estimated costs and schedule, and that it was in the best interests of Progress Energy Florida's customers and joint owners and Duke Energy's investors to retire the unit. Progress Energy Florida developed initial estimates of the cost to decommission the plant during its analysis of whether to repair or retire Crystal River Unit 3. With the final decision to retire, Progress 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. Progress Energy Florida intends to use a safe storage (SAFSTOR) option for decommissioning. Generally, SAFSTOR involves placing the facility into a safe storage configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur, usually in 40 to 60 years. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Once an updated site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed which resulted in an estimate in 2011 dollars of $989 million. See Note 9 for additional information. Additional specifics about the decommissioning plan are being developed.

Progress Energy Florida maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at Crystal River Unit 3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded the insurance coverage. Progress Energy Florida also maintains insurance coverage through NEIL's accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

Throughout the duration of the Crystal River Unit 3 outage, Progress Energy Florida worked with NEIL for recovery of applicable repair costs and associated replacement power costs. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL had not provided a written coverage decision for either delamination and no payments were made on the second delamination and no replacement power reimbursements were made by NEIL since May 2011. These considerations led Progress Energy Florida to conclude, in the second quarter of 2012, that it was not probable that NEIL would voluntarily pay the full coverage amounts that Progress Energy Florida believes them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, Progress Energy Florida agreed to non-binding mediation prior to commencing any formal dispute resolution. On February 5, 2013, Progress Energy Florida announced it and NEIL had accepted the mediator's proposal whereby NEIL will pay Progress Energy Florida an additional $530 million. Along with the $305 million which NEIL previously paid, Progress Energy Florida will receive a total of $835 million in insurance proceeds.

The following table summarizes the Crystal River Unit 3 replacement power and repair costs and recovery through December 31, 2012.

(in millions)			Replacement Power Costs		Repair Costs		Total
Spent to date		$	614	$	338	$	952
NEIL proceeds received to date			(162)		(143)		(305)
Balance for recovery^(a)		$	452	$	195	$	647

(a)	The portion of replacement power costs that has not been previously recovered from retail customers is classified within Regulatory assets on Duke Energy's Consolidated Balance Sheets and Progress Energy Florida's Balance Sheet as of December 31, 2012. Also, the $195 million of repair costs are classified within Regulatory assets on Duke Energy's Consolidated Balance Sheets and Progress Energy Florida's Balance Sheets as of December 31, 2012.

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

In accordance with the terms of the 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retained the sole discretion to retire Crystal River Unit 3. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013.

Progress Energy Florida did not begin the repair of Crystal River Unit 3 prior to December 31, 2012. Consistent with the 2012 FPSC Settlement Agreement regarding the timing of commencement of repairs, Progress Energy Florida recorded a Regulatory liability of $100 million in the third quarter of 2012 related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in Progress Energy Florida's and Progress Energy's Statements of Operations and Comprehensive Income for the year ended December 31, 2012. Progress Energy Florida will refund this replacement power liability on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy's Consolidated Financial Statements.

Progress Energy Florida also retained sole discretion to retire the unit without challenge from the parties to the agreement. As a result, Progress Energy Florida will be allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017.

In conjunction with the decision to retire Crystal River Unit 3, Progress Energy Florida reclassified all Crystal River Unit 3 investments, including property, plant and equipment; nuclear fuel; inventory; and deferred assets to a regulatory asset account. At December 31, 2012, Progress Energy Florida had $1,637 million of net investment in Crystal River Unit 3 recorded in Regulatory assets on its Consolidated Balance Sheet. These amounts are reflected in the Regulatory Assets and Liabilities tables presented previously in this disclosure, of which $1,592 million is reflected as Retired generation facilities, $25 million as Nuclear deferral and $20 million as an offset to Removal costs. Progress Energy Florida recorded $192 million of impairment and other charges related to the wholesale portion of Crystal River Unit 3 investments, which are not covered by the 2012 FSPC Settlement Agreement, and other provisions. The significant majority of this amount is recorded in Impairment charges on Progress Energy Florida's and Progress Energy's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy's Consolidated Financial Statements (See Note 2).

In accordance with the 2012 FPSC Settlement Agreement, NEIL proceeds received allocable to retail customers will be applied first to replacement power costs incurred after December 31, 2012 through December 31, 2016, with the remainder used to write down the remaining Crystal River Unit 3 investments.

Progress Energy Florida believes the decision to retire Crystal River Unit 3, the actions taken and costs incurred in response to the Crystal River Unit 3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and exit cost to wind down the operations at the plant and decommission Crystal River Unit 3 could be material. Retirement of the plant could impact funding obligations associated with Progress Energy Florida's nuclear decommissioning trust fund.

Progress 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 Progress Energy Florida and the joint owners. In December 2012, Progress Energy Florida reached an agreement with one group of joint owners related to all Crystal River Unit 3 matters.

Customer Rate Matters. In conjunction with the 2012 FPSC Settlement Agreement, Progress Energy Florida will maintain base rates at the current levels through the last billing cycle of December 2016, except as described as follows. The agreement provides for a $150 million increase in revenue requirements effective with the first billing cycle of January 2013, while maintaining the current return on equity range of 9.5 percent to 11.5 percent. Additionally, costs associated with Crystal River Unit 3 investments will be removed from retail rate base effective with the first billing cycle of January 2013. Progress Energy Florida will accrue, for future rate-setting purposes, a carrying charge on the Crystal River Unit 3 investment until the Crystal River Unit 3 regulatory asset is recovered in base rates beginning with the first billing cycle of January 2017. If Progress 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 Progress Energy Florida monthly earnings surveillance report, Progress Energy Florida may petition the FPSC to amend its base rates during the term of the agreement. Refer to the discussion above regarding recovery of Crystal River Unit 3 investments if the plant is retired.

Progress Energy Florida will refund $288 million to retail customers through its fuel clause. Progress Energy Florida will refund $129 million in each of 2013 and 2014, and an additional $10 million annually to residential and small commercial customers in 2014, 2015 and 2016. At December 31, 2011, a regulatory liability was established for the $288 million to be refunded in future periods. In 2011, the corresponding charge was recorded as a reduction of operating revenues in Progress Energy Florida's and Progress Energy's Consolidated Statements of Operations and Comprehensive Income. As discussed above, Progress Energy Florida also recorded a Regulatory liability of $100 million in the third quarter of 2012 related to replacement power obligations.

Levy Nuclear Station. On July 30, 2008, Progress Energy Florida filed its COL application with the NRC for two Westinghouse AP1000 reactors at its proposed Levy Nuclear Station (Levy), which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application. On October 31 and November 1, 2012, the Atomic Safety and Licensing Board held an evidentiary hearing on portions of the intervention petitions. A decision is expected in March 2013. In 2008, the FPSC granted Progress Energy Florida's petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida's nuclear cost-recovery rule for Levy, together with the associated facilities, including transmission lines and substation facilities.

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

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

Under the terms of the 2012 FSPC Settlement Agreement, Progress Energy Florida began residential cost-recovery of its proposed Levy Nuclear Station effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement and continuing for a five-year period, with true-up of any actual costs not recovered during the 5-year period occurring in the final year. Progress Energy Florida will not file for recovery of any new Levy costs that were not addressed in the 2012 FSPC Settlement Agreement before March 1, 2017 and will not begin recovering those costs from customers before the first billing cycle of January, 2018, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the COL and any engineering, procurement and construction cancellation costs, if Progress Energy Florida ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose Progress Energy Florida continuing to pursue a COL for Levy. The 2012 FSPC Settlement Agreement also provides that Progress Energy Florida will treat the allocated wholesale cost of Levy (approximately $68 million) as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. Progress Energy Florida will have the discretion to accelerate and/or suspend such amortization in full or in part provided that it amortizes all of the regulatory asset by December 31, 2016.

Cost of Removal Reserve. The 2012 and 2010 FPSC Settlement Agreements (Settlement Agreements) provide Progress Energy Florida the discretion to reduce cost of removal amortization expense by up to the balance in the cost of removal reserve until the earlier of (a) its applicable cost of removal reserve reaches zero, or (b) the expiration of the 2012 FPSC Settlement Agreement. Progress Energy Florida may not reduce amortization expense if the reduction would cause it to exceed the appropriate high point of the return on equity range, as established in the Settlement Agreements. Pursuant to the Settlement Agreements, Progress Energy Florida recognized a reduction in amortization expense of $178 million and $250 million for the years ended December 31, 2012 and 2011, respectively. Duke Energy recognized a reduction in amortization expense of $120 million for the year ended December 31, 2012. Progress Energy Florida had eligible cost of removal reserves of $110 million remaining at December 31, 2012, which is impacted by accruals in accordance with its latest depreciation study, removal costs expended and reductions in amortization expense as permitted by the Settlement Agreements.

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

Capacity Rider Filing. On August 29, 2012, Duke Energy Ohio filed an application with the PUCO for the establishment of a charge, pursuant to Ohio's state compensation mechanism, for capacity provided consistent with its obligations as a Fixed Resource Requirement (FRR) entity. The application included a request for deferral authority and for a new tariff to implement the charge. The deferral being sought is the difference between its costs and market-based prices for capacity. The requested tariff would implement a charge to be collected via a rider through which such deferred balances will subsequently be recovered. 24 parties moved to intervene. Hearings have been set for April 2, 2013. Under the current procedural schedule, Duke Energy Ohio expects an order in 2013.

2012 Electric Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in electric distribution rates of approximately $87 million. On average, total electric rates would increase approximately 5.1% under the filing. The rate increase is designed to recover the cost of investments in projects to improve reliability for customers and upgrades to the distribution system. Pursuant to a stipulation in another case, Duke Energy Ohio will continue recovering its costs associated with grid modernization in a separate rider.

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

2012 Natural Gas Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in natural gas distribution rates of approximately $45 million. On average, total natural gas rates would increase approximately 6.6% under the filing. The rate increase is designed to recover the cost of upgrades to the distribution system, as well as environmental cleanup of manufactured gas plant sites. In addition to the recovery of costs associated with MGP sites, the rate request includes a proposal for an accelerated service line replacement program and a new rider to recover the associated incremental cost. The filing also requests that the PUCO renew the rider recovery of Duke Energy Ohio's accelerated main replacement program and grid modernization program.

On January 4, 2013, the PUCO Staff filed a staff report recommending that Duke Energy Ohio only be allowed to recover costs related to MGP sites which are currently used and useful in the provision of natural gas distribution service. Duke Energy Ohio filed its objection to the staff report on February 4, 2013.

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

Generation Asset Transfer. 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 Franchised Electric and Gas 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 has agreed to transfer the legacy coal-fired and combustion gas turbine assets on or before December 31, 2014.

Standard Service Offer (SSO). The PUCO approved Duke Energy Ohio's current Electric Security Plan (ESP) on November 22, 2011. The ESP effectively separates the generation of electricity from Duke Energy Ohio's retail load obligation and requires Duke Energy Ohio to transfer its generation assets to a nonregulated affiliate on or before December 31, 2014. The ESP includes competitive auctions for electricity supply whereby the energy price is recovered from retail customers. As a result, Duke Energy Ohio now earns retail margin on the transmission and distribution of electricity only and not on the cost of the underlying energy. New rates for Duke Energy Ohio went into effect for SSO customers on January 1, 2012. The ESP also includes a provision for a non-bypassable stability charge of $110 million per year to be collected from January 1, 2012 through December 31, 2014.

On January 18, 2012, the PUCO denied a request for rehearing of its decision on Duke Energy Ohio's ESP filed by Columbus Southern Power and Ohio Power Company.

Regional Transmission Organization Realignment. 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 MISO to PJM, effective December 31, 2011.

On December 16, 2010, the FERC issued an order related to MISO's cost allocation methodology surrounding Multi-Value Projects (MVP), a type of MISO Transmission Expansion Planning (MTEP) project cost. MISO expects that MVP will fund the costs of large transmission projects designed to bring renewable generation from the upper Midwest to load centers in the eastern portion of the MISO footprint. MISO approved MVP proposals with estimated project costs of approximately $5.2 billion prior to the date of Duke Energy Ohio's exit from MISO on December 31, 2011. These projects are expected to be undertaken by the constructing transmission owners from 2012 through 2020 with costs recovered through MISO over the useful life of the projects. The FERC order did not clearly and expressly approve MISO's apparent interpretation that a withdrawing transmission owner is obligated to pay its share of costs of all MVP projects approved by MISO up to the date of the withdrawing transmission owners' exit from MISO. Duke Energy Ohio has historically represented approximately five-percent of the MISO system. Duke Energy Ohio, among other parties, sought rehearing of the FERC MVP order. On October 21, 2011, the FERC issued an order on rehearing in this matter largely affirming its original MVP order and conditionally accepting MISO's compliance filing as well as determining that the MVP allocation methodology is consistent with cost causation principles and FERC precedent. The FERC also reiterated that it would not prejudge any settlement agreement between an RTO and a withdrawing transmission owner for fees that a withdrawing transmission owner owes to the RTO. The order further states that any such fees that a withdrawing transmission owner owes to an RTO are a matter for those parties to negotiate, subject to review by the FERC. The FERC also ruled that Duke Energy Ohio's challenge of MISO's ability to allocate MVP costs to a withdrawing transmission owner is beyond the scope of the proceeding. The order further stated that MISO's tariff withdrawal language establishes that once cost responsibility for transmission upgrades is determined, withdrawing transmission owners retain any costs incurred prior to the withdrawal date. In order to preserve its rights, Duke Energy Ohio filed an appeal of the FERC order in the D.C. Circuit Court of Appeals. The case was consolidated with appeals of the FERC order by other parties in the Seventh Circuit Court of Appeals.

On October 14, 2011, Duke Energy Ohio filed an application with the FERC to establish new wholesale customer rates for transmission service under PJM's Open Access Transmission Tariff. In this filing, Duke Energy Ohio sought recovery of its legacy MTEP costs, including MVP costs, and submitted an analysis showing that the benefits of the RTO realignment outweigh the costs to the customers. The new rates went into effect, subject to refund, on January 1, 2012. Protests were filed by certain transmission customers. On April 24, 2012, FERC issued an order in which it, denied recovery of legacy MTEP costs without prejudice to the right of Duke Energy Ohio to make another filing including a more comprehensive cost-benefit analysis to support such recovery and set the return on equity component of the rate for hearing. Duke Energy Ohio has entered into a settlement agreement with the only remaining protester, American Municipal Power, Inc. (AMP) under which the return on equity will be set at 11.38% legacy MTEP costs will be recovered in rates, and AMP will receive a credit equal to 75% of its share of the legacy MTEP costs. The settlement agreement was filed with the FERC on February 4, 2012 and requires FERC approval.

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

On March 28, 2012, Duke Energy Ohio filed a request for rehearing of FERC's February 27, 2012 order on MISO's Schedule 39. On December 19, 2012, the FERC Trial Staff submitted testimony in the Schedule 39 hearing proceeding in which its witness stated his opinion that Duke Energy Ohio should not be liable for any MVP costs. The role of the FERC Trial Staff is to act as an independent party in the proceeding; it has no judicial authority. The hearing has been scheduled for April 2013.

On December 31, 2011, Duke Energy Ohio recorded a liability for its MISO exit obligation and share of MTEP costs, excluding MVP, of approximately $110 million. 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 upon exit from MISO on December 31, 2011. Approximately $74 million of this amount was recorded as a regulatory asset while $36 million was recorded to Operation, maintenance and other in Duke Energy Ohio's Consolidated Statements of Operations and Comprehensive Income. In addition to the above amounts, Duke Energy Ohio may also be responsible for costs associated with MISO MVP projects. Duke Energy Ohio is contesting its obligation to pay for such costs. However, depending on the final outcome of this matter, Duke Energy Ohio could incur material costs associated with MVP projects, which are not reasonably estimable at this time. Regulatory accounting treatment will be pursued for any costs incurred in connection with the resolution of this matter.

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

Edwardsport IGCC Plant. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a CPCN for the construction of a 618 MW IGCC power plant at Duke Energy Indiana's Edwardsport Generating Station in Knox County, Indiana with a cost estimate of $1.985 billion and timely recovery of 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., Save the Valley, Inc., and Valley Watch, Inc., all intervenors in the CPCN proceeding, have appealed the air permit.

On May 1, 2008, Duke Energy Indiana filed its first semi-annual IGCC rider and ongoing review proceeding with the IURC as required under the CPCN order issued by the IURC. In its filing, Duke Energy Indiana requested approval of a new cost estimate for the IGCC project of $2.35 billion (including $125 million of AFUDC) and for approval of plans to study carbon capture as required by the IURC's CPCN order. On January 7, 2009, the IURC approved Duke Energy Indiana's request, including the new cost estimate of $2.35 billion, and cost recovery associated with a study on carbon capture. On November 3, 2008 and May 1, 2009, Duke Energy Indiana filed its second and third semi-annual IGCC riders, respectively, both of which were approved by the IURC in full.

On November 24, 2009, Duke Energy Indiana filed a petition for its fourth semi-annual IGCC rider and ongoing review proceeding with the IURC. As Duke Energy Indiana experienced design modifications, quantity increases and scope growth above what was anticipated from the preliminary engineering design, capital costs to the IGCC project were anticipated to increase. Duke Energy Indiana forecasted that the additional capital cost items would use the remaining contingency and escalation amounts in the current $2.35 billion cost estimate and add $150 million, excluding the impact associated with the need to add more contingency. Duke Energy Indiana did not request approval of an increased cost estimate in the fourth semi-annual update proceeding; rather, Duke Energy Indiana requested, and the IURC approved, a subdocket proceeding in which Duke Energy Indiana would present additional evidence regarding an updated estimated cost for the IGCC project and in which a more comprehensive review of the IGCC project could occur. The evidentiary hearing for the fourth semi-annual update proceeding was held April 6, 2010, and an interim order was received on July 28, 2010. The order approved the implementation of an updated IGCC rider to recover costs incurred through September 30, 2009. The approvals were on an interim basis pending the outcome of the sub-docket proceeding involving the revised cost estimate as discussed further below.

On April 16, 2010, Duke Energy Indiana filed a revised cost estimate for the IGCC project reflecting an estimated cost increase of $530 million. Duke Energy Indiana requested approval of the revised cost estimate of $2.88 billion (including $160 million of AFUDC), and for continuation of the existing cost recovery treatment. A major driver of the cost increase included quantity increases and design changes, which impacted the scope, productivity and schedule of the IGCC project. On September 17, 2010, an agreement was reached with the Indiana Office of Utility Consumer Counselor (OUCC), Duke Energy Indiana Industrial Group and Nucor Steel Indiana to increase the authorized cost estimate of $2.35 billion to $2.76 billion, and to cap the project's costs that could be passed on to customers at $2.975 billion. Any construction cost amounts above $2.76 billion would be subject to a prudence review similar to most other rate base investments in Duke Energy Indiana's next general rate increase request before the IURC. Duke Energy Indiana agreed to accept a 150 basis point reduction in the equity return for any project construction costs greater than $2.35 billion. Additionally, Duke Energy Indiana agreed not to file for a general rate case increase before March 2012. Duke Energy Indiana also agreed to reduce depreciation rates earlier than would otherwise be required and to forego a deferred tax incentive related to the IGCC project. As a result of the settlement, Duke Energy Indiana recorded a pre-tax charge to earnings of approximately $44 million in the third quarter of 2010 to reflect the impact of the reduction in the return on equity. The charge is recorded in Impairment charges on the Consolidated Statements of Operations and Comprehensive Income. The IURC convened a technical conference on November 3, 2010, related to the continuing need for the Edwardsport IGCC facility. On December 9, 2010, the parties to the settlement withdrew the settlement agreement to provide an opportunity to assess whether and to what extent the settlement agreement remained a reasonable allocation of risks and rewards and whether modifications to the settlement agreement were appropriate. Management determined that the approximate $44 million charge discussed above was not impacted by the withdrawal of the settlement agreement.

During 2010, Duke Energy Indiana filed petitions for its fifth and sixth semi-annual IGCC riders. Evidentiary hearings were held on April 24, 2012 and April 25, 2012.

The CAC, Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc. filed motions for two subdocket proceedings alleging improper communications, undue influence, fraud, concealment and gross mismanagement, and a request for field hearing in this proceeding. Duke Energy Indiana opposed the requests. On February 25, 2011, the IURC issued an order which denied the request for a subdocket to investigate the allegations of improper communications and undue influence at this time, finding there were other agencies better suited for such investigation. The IURC also found that allegations of fraud, concealment and gross mismanagement related to the IGCC project should be heard in a Phase II proceeding of the cost estimate subdocket and set evidentiary hearings on both Phase I (cost estimate increase) and Phase II beginning in August 2011. After procedural delays, hearings began on Phase I on October 26, 2011 and on Phase II on November 21, 2011.

On March 10, 2011, Duke Energy Indiana filed testimony with the IURC proposing a framework designed to mitigate customer rate impacts associated with the Edwardsport IGCC project. Duke Energy Indiana's filing proposed a cap on the project's construction costs, (excluding financing costs), which can be recovered through rates at $2.72 billion. It also proposed rate-related adjustments that would lower the overall customer rate increase related to the project from an average of 19% to approximately 16%.

On June 27, 2011, Duke Energy Indiana filed testimony with the IURC in connection with its seventh semi-annual rider request which included an update on the current cost forecast of the Edwardsport IGCC project. The updated forecast, excluding AFUDC, increased from $2.72 billion to $2.82 billion, not including any contingency for unexpected start-up events. On June 30, 2011, the OUCC and intervenors filed testimony in Phase I recommending that Duke Energy Indiana be disallowed cost recovery of any of the additional cost estimate increase above the previously approved cost estimate of $2.35 billion. Duke Energy Indiana filed rebuttal testimony on August 3, 2011.

In the subdocket proceeding, on July 14, 2011, the OUCC and certain intervenors filed testimony in Phase II alleging that Duke Energy Indiana concealed information and grossly mismanaged the project, and therefore Duke Energy Indiana should only be permitted to recover from customers $1.985 billion, the original IGCC project cost estimate approved by the IURC. Other intervenors recommended that Duke Energy Indiana not be able to rely on any cost recovery granted under the CPCN or the first cost increase order. Duke Energy Indiana believes it has diligently and prudently managed the project. On September 9, 2011, Duke Energy defended against the allegations in its responsive testimony. The OUCC and intervenors filed their final rebuttal testimony in Phase II on or before October 7, 2011, making similar claims of fraud, concealment and gross mismanagement and recommending the same outcome of limiting Duke Energy Indiana's recovery to the $1.985 billion initial cost estimate. Additionally, the CAC recommended that recovery be limited to the costs incurred on the IGCC project as of November 30, 2009, with further IURC proceedings to be held to determine the financial consequences of this recommendation. As of November 30, 2009, Duke Energy Indiana estimated it had committed costs of $1.6 billion.

On October 19, 2011, Duke Energy Indiana revised its project cost estimate from approximately $2.82 billion, excluding financing costs, to approximately $2.98 billion, excluding financing costs. The revised estimate reflects additional cost pressures resulting from quantity increases and the resulting impact on the scope, productivity and schedule of the IGCC project. Duke Energy Indiana previously proposed to the IURC a cost cap of approximately $2.72 billion, plus the actual AFUDC that accrues on that amount. As a result, Duke Energy Indiana recorded a pre-tax impairment charge of approximately $222 million in the third quarter of 2011 related to costs expected to be incurred above the cost cap. This charge is in addition to the previous pre-tax impairment charge related to the Edwardsport project discussed above and is recorded in Impairment charges on the Consolidated Statements of Operations and Comprehensive Income.

On November 30, 2011, Duke Energy Indiana filed a petition with the IURC in connection with its eighth semi-annual rider request for the Edwardsport IGCC project. Evidentiary hearings for the seventh and eighth semi-annual rider requests were held on August 6, 2012 and August 7, 2012.

Phase I and Phase II hearings concluded on January 24, 2012. The CAC has filed repeated requests for the IURC to consider issues of ethics, undue influence, due process violations and appearance of impropriety. The IURC denied the most recent motion in March 2012. In April 2012, the CAC filed a motion requesting the IURC to certify questions of law for appeal regarding allegations of fraud on the commission and due process violations. This motion was denied.

On April 30, 2012, Duke Energy Indiana entered into a settlement agreement with the OUCC, the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana on the cost increase for construction of the Edwardsport IGCC plant, including both Phase I and Phase II of the subdocket. Pursuant to the agreement, there would be a cap on costs to be reflected in customer rates of $2.595 billion, including estimated financing costs through June 30, 2012. Pursuant to the agreement, Duke Energy Indiana would be able to recover additional financing costs until November 30, 2012, and 85% of financing costs that accrue thereafter. 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. As a result of the agreement, Duke Energy Indiana recorded pre-tax impairment and other charges of approximately $420 million in the first quarter of 2012. Approximately $400 million is recorded in Impairment charges and the remaining approximately $20 million is recorded in Operation, maintenance and other on Duke Energy's Consolidated Statement of Operations and in Duke Energy Indiana's Consolidated Statements of Operations and Comprehensive Income. The $20 million recorded in Operation, maintenance and other, is attributed to legal fees Duke Energy Indiana will be responsible for on behalf of certain intervenors, as well as funding for low income energy assistance, as required by the settlement agreement. These charges are in addition to previous pre-tax impairment charges related to the Edwardsport IGCC project as discussed above.

The CAC, Sierra Club Indiana chapter, Save the Valley and Valley Watch, filed testimony in opposition to the April 30, 2012 settlement agreement contending the agreement should not be approved, and that the amount of costs recovered from customers should be less than what the settlement agreement provides, potentially even zero. In addition to reiterating their prior concerns with the Edwardsport IGCC project, the intervenors noted above also contend new settlement terms should be added to mitigate carbon emissions, conditions should be added prior to the plant being declared in-service and the IURC should consider their allegations of undue influence. Duke Energy Indiana, the Industrial Group and the OUCC, filed rebuttal testimony supporting the settlement as reasonable and in the public interest. An evidentiary hearing on the settlement agreement concluded on July 19, 2012. Post-hearing briefing has been completed.

On June 8, 2012, Duke Energy Indiana filed a petition with the IURC in connection with its ninth semi-annual rider request for the Edwardsport IGCC project. An evidentiary hearing for the ninth semi-annual rider request was January 15, 2013.

On October 30, 2012, Duke Energy Indiana revised its project cost estimate from approximately $2.98 billion, excluding financing costs, to approximately $3.154 billion, excluding financing costs, and revised the projected in-service date from the first quarter of 2013 to the second quarter of 2013. The revised estimate is due primarily to lower than projected revenues from test output and delays due to more extensive testing conditions. As a result, Duke Energy Indiana recorded a pre-tax impairment charge of approximately $180 million in the third quarter of 2012 related to costs expected to be incurred above the cost cap proposed in the settlement agreement filed in April 2012, as discussed above. This amount is in addition to previous pre-tax impairment charges related to the Edwardsport IGCC project and is recorded in Impairment charges on Duke Energy's Consolidated Statements of Operations and Duke Energy Indiana's Consolidated Statements of Operations and Comprehensive Income.

On December 27, 2012, the IURC approved the settlement agreement finalized in April 2012, as discussed above, between Duke Energy Indiana, the OUCC, the Duke Energy Indiana Industrial Group and Nucor Steel Indiana, on the cost increase for the construction of the project. This order resolves all subdocket issues in Phase I and Phase II of the proceeding. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595 billion, including estimated AFUDC through June 30, 2012. Duke Energy Indiana was allowed to recover AFUDC after June 30, 2012 until customer rates are revised, with such recovery decreasing to 85% on AFUDC accrued after November 30, 2012.

The IURC modified the settlement agreement as previously agreed to by the parties to (i) require the Duke Energy Indiana to credit customers $31 million for cost control incentive payments which the IURC found to be unwarranted as a result of delays that arose from project cost overruns and (ii) provide that if the Duke Energy Indiana should recover more than the project costs absorbed by Duke Energy's shareholders through litigation, any surplus must be returned to the Duke Energy Indiana's ratepayers. On December 11, 2012, Duke Energy Indiana filed an arbitration action against General Electric Company (General Electric) and Bechtel Corporation (Bechtel) in connection with their work at the Edwardsport IGCC facility. Duke Energy Indiana is seeking damages of not less than $560 million. Duke Energy cannot predict the outcome of this matter.

The CAC, Sierra Club Indiana chapter, Save the Valley and Valley Watch have appealed the IURC order approving the Settlement Agreement to the Indiana Court of Appeals. No briefing schedule has been set.

Also on December 27, 2012, the IURC issued orders on the fifth, sixth, seventh and eighth IGCC riders, concluding those proceedings. In the eighth IGCC rider order, the IURC approved construction work in process recovery on the settlement agreement's hard cost cap amount of $2.595 billion.

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

Duke Energy Indiana Storm Cost Deferrals. On July 14, 2010, the IURC approved Duke Energy Indiana's deferral of $12 million of retail jurisdictional storm expense until the next retail rate proceeding. This amount represents a portion of costs associated with a January 27, 2009 ice storm, which damaged Duke Energy Indiana's distribution system. On August 12, 2010, the OUCC filed a notice of appeal with the IURC. On December 7, 2010, the IURC issued an order reopening this proceeding for review in consideration of the evidence presented as a result of an internal audit performed as part of an IURC investigation of Duke Energy Indiana's hiring of an attorney from the IURC staff which resulted in the IURC's termination of the employment of the Chairman of the IURC. The audit did not find that the order conflicted with the staff report; however, it did note that the staff report offered no specific recommendation to either approve or deny the requested relief, and that the original order was appealed. On October 19, 2011, the IURC issued an order denying Duke Energy Indiana the right to defer the storm expense discussed above. On December 29, 2012, the Indiana Court of Appeals upheld the IURC's decision to deny recovery of the storm costs.

Phase 2 Environmental Compliance Proceeding. On June 28, 2012, Duke Energy Indiana filed with the IURC a plan for the addition of certain environmental pollution control projects on several of its coal-fired generating units in order to comply with existing and proposed environmental rules and regulations. The plan calls for a combination of selective catalytic reduction systems, dry sorbent injection systems for SO3 mitigation, activated carbon injection systems and/or mercury re-emission chemical injection systems. The capital costs are estimated at $395 million (excluding AFUDC). Duke Energy Indiana also indicated that it preliminarily anticipates the retirement of Wabash River Units 2 through 5 in 2015 and is still evaluating future equipment additions or retirement of Wabash River Unit 6. An evidentiary hearing was held January 7, 2013 through January 9, 2013, with an order expected in the second quarter of 2013.

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

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

On November 29, 2012, Duke Energy reached a settlement agreement with the NCUC and the North Carolina Public Staff regarding the investigations discussed above. Pursuant to the settlement agreement, Duke Energy agreed to a number of terms, the most notable of which are (i) Duke Energy will maintain at least 1,000 employees in Raleigh, North Carolina for at least five years from date of the settlement agreement; (ii) Duke Energy will guarantee an additional $25 million in fuel and fuel-related cost savings for Duke Energy's North Carolina retail customers; (iii) Duke Energy will contribute an additional $5 million to workforce development and low-income assistance in North Carolina; (iv) Duke Energy Carolinas will defer filing a general rate case in North Carolina until February 2013; and (v) Duke Energy will make various changes in management and Board members, which includes CEO James E. Rogers retirement no later than December 31, 2013. On December 3, 2012, the NCUC approved the settlement agreement between Duke Energy, the NCUC and the North Carolina Public Staff. The settlement agreement resolves all matters related to the NCUC investigation.

Duke Energy has also been contacted by the SEC to explain the circumstances surrounding the NCUC Investigation and shareholder lawsuits in connection with the closing of the merger with Progress Energy. See Note 5 for a discussion of shareholder litigation. A meeting was held with the SEC staff in late October. Duke Energy intends to continue to assist the SEC staff, as they request.

Progress Energy Merger North Carolina Department of Justice (NCDOJ) Investigations. Duke Energy also received an Investigative Demand issued by the NCDOJ on July 6, 2012, requesting the production of certain documents related to the issues which were also the subject of the NCUC Investigation discussed above. Duke Energy's responses to these requests were submitted on August 7, 2012. On August 1, 2012, the NCUC engaged the law firm of Jenner & Block to conduct an investigation of these matters. On December 3, 2012, Duke Energy reached a settlement agreement with the NCDOJ.

Joint Dispatch Agreement (JDA). On June 29, 2012, and July 2, 2012, the NCUC and the PSCSC, respectively, approved the JDA between Duke Energy Carolinas and Progress Energy Carolinas. The JDA provides for joint dispatch of the generating facilities of both Duke Energy Carolinas and Progress Energy Carolinas for the purpose of reducing the cost of serving the native loads of both companies. As set forth in the JDA, Duke Energy Carolinas will act as the joint dispatcher, on behalf of both Duke Energy Carolinas and Progress Energy Carolinas. As joint dispatcher, Duke Energy Carolinas will direct the dispatch of both Duke Energy Carolinas' and Progress Energy Carolinas' power supply resources, determine payments between the parties for the purchase and sale of energy between Duke Energy Carolinas and Progress Energy Carolinas, and calculate and allocate the fuel cost savings to the parties. The JDA is subject to review by the PSCSC after one year. Refer to Note 14 for further discussion.

Planned and Potential Coal Plant Retirements. The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (15-20 years), and options being considered to meet those needs. The IRP's filed by the Subsidiary Registrants in 2012 and 2011 included planning assumptions to potentially retire by 2015, certain coal-fired generating facilities in North Carolina, South Carolina, Indiana and Ohio that do not have the requisite emission control equipment, primarily to meet Environmental Protection Agency (EPA) regulations that are not yet effective. Additionally, management is considering the impact pending environmental regulations might have on certain coal-fired generating facilities in Florida.

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. In addition to the amounts presented below, Progress Energy Carolinas and Duke Energy Indiana have $128 million and $61 million, respectively, of net carrying value related to previously retired generation facilities included in Regulatory assets on their Consolidated Balance Sheets.

		December 31, 2012
			Duke Energy		Duke Energy Carolinas^(b)(e)		Progress Energy Carolinas^(c)(e)		Progress Energy Florida^(d)		Duke Energy Ohio^(f)		Duke Energy Indiana^(g)
Capacity (in MW)			3,954		910		575		873		928		668
Remaining net book value (in millions)^(a)		$	428	$	106	$	63	$	115	$	12	$	132

(a)	Included in Property, plant and equipment, net as of December 31, 2012, on the Consolidated Balance Sheets, unless otherwise noted.
(b)	Includes Riverbend Units 4 through 7, Lee Units 1 and 2 and Buck Units 5 and 6. Duke Energy Carolinas has committed to retire 1,667 MW in conjunction with a Cliffside air permit settlement, of which 587 MW have already been retired as of December 31, 2012. Duke Energy Carolinas plans to retire 710 MW for the Riverbend Units 4 though 7 and Buck Units 5 and 6 effective April 1, 2013. Excludes 170 MW Lee Unit 3 that is expected to be converted to gas in 2014. The Lee Unit 3 conversion will be considered a retirement toward meeting the 1,667 MW retirement commitment.
(c)	Includes Sutton Station, which is expected to be retired by the end of 2013.
(d)	Includes Crystal River Units 1 and 2.
(e)	Net book value of Duke Energy Carolinas' Buck Units 5 and 6 of $73 million, and Progress Energy Carolinas' Sutton Station of $63 million is included in Generation facilities to be retired, net, on the Consolidated Balance Sheets at December 31, 2012.
(f)	Includes Beckjord Station Units 2 through 6 and Miami Fort Unit 6. Beckjord has no remaining book value. Beckjord Unit 1 was retired May 1, 2012.
(g)	Includes Wabash River Units 2 through 6.

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