4. Regulatory Matters

Regulatory Assets and Liabilities.

As of December 31, 2011 and 2010, the substantial majority of USFE&G's operations applied regulatory accounting treatment. From 2009 through 2011, certain portions of Commercial Power's operations applied regulatory accounting treatment; however, effective November 2011, as a result of the new Electric Security Plan (ESP), regulatory accounting treatment will no longer be applied. 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.

Duke Energy Registrants' Regulatory Assets and Liabilities:


As of December 31, 2011	Duke Energy		Duke Energy Carolinas		Duke Energy Ohio		Duke Energy Indiana		Recovery/Refund Period Ends^(k)
	(in millions)
Regulatory Assets^(a)
Vacation accrual	$	150	$	70	$	7	$	13		2012
Under-recovery of fuel costs		38		—		10		28		2012
Hedge costs and other deferrals		4		3		1		—		2012
Post-in-service carrying costs and deferred operating expense^(c)(l)		31		28		—		3		2012
Over-distribution of Bulk Power Marketing sharing		41		41		—		—		2012
Demand side management costs (DSM costs)/Energy Efficiency		43		25		—		18		2012
Regional Transmission Organization (RTO) costs^(m)		17		5		—		12		2012
SmartGrid		9		—		9		—		2012
Gasification services agreement buyout costs		25		—		—		25		2012
Other		16		—		1		15		2012

Total Current Regulatory Assets^(d)		374		172		28		114


Net regulatory asset related to income taxes^(e)		892		668		77		147		^(h	⁾
Accrued pension and post-retirement		1,726		734		212		314		^(b	⁾
ARO costs		191		191		—		—		2043
Gasification services agreement buyout costs		88		—		—		88		2018
Deferred debt expense^(e)		122		98		8		16		2041
Post-in-service carrying costs and deferred operating expense^(c)(l)		119		31		16		72		^(h	⁾
Under-recovery of fuel costs		13		13		—		—		2013
Hedge costs and other deferrals		166		91		8		67		^(b	⁾
Storm cost deferrals		18		—		18		—		^(b	⁾
Manufactured gas plant environmental costs		69		—		69		—		^(b	⁾
Smart Grid		32		—		32		—		^(b	⁾
Gallagher Units 1 & 3		73		—		—		73		^(b	⁾
RTO costs^(m)		80		13		74		—		^(b	⁾
DSM costs/Energy Efficiency		38		38		—		—		^(b	⁾
Other		45		17		6		21		^(b	⁾

Total Non-Current Regulatory Assets		3,672		1,894		520		798

Total Regulatory Assets	$	4,046	$	2,066	$	548	$	912

Regulatory Liabilities^(a)
Nuclear property and insurance reserves	$	2	$	2	$	—	$	—		2012
DSM costs^(f)		41		41		—		—		2012
Gas purchase costs		20		—		20		—		2012
Over-recovery of fuel costs^(f)		6		6		—		—		2012
Other		18		13		2		3		2012

Total Current Regulatory Liabilities^(g)		87		62		22		3


Removal costs^(e)		2,586		1,770		230		590		^(j	⁾
Nuclear property and liability reserves		86		86		—		—		2043
DSM costs^(f)/Energy Efficiency		27		10		17		—		⁽ⁱ	⁾
Accrued pension and other post-retirement benefits		117		—		19		70		^(b	⁾
Commodity contract termination settlement		23		—		—		23		2014
Injuries and damages reserve^(e)		38		38		—		—		^(b	⁾
Hedge costs and other deferrals^(e)		12		—		—		—		2016
Other		30		24		7		—		^(b	⁾

Total Non-Current Regulatory Liabilities		2,919		1,928		273		683

Total Regulatory Liabilities	$	3,006	$	1,990	$	295	$	686


As of December 31, 2010	Duke Energy		Duke Energy Carolinas		Duke Energy Ohio		Duke Energy Indiana		Recovery/Refund Period Ends^(k)
	(in millions)
Regulatory Assets^(a)
Vacation accrual	$	146	$	67	$	8	$	13		2011
Under-recovery of fuel costs		31		—		12		19		2011
Post-in-service carrying costs and deferred operating expense^(c)(l)		28		28		—		—		2011
Over-distribution of Bulk Power Marketing sharing		35		35		—		—		2011
Other		15		6		—		9		2011

Total Current Regulatory Assets^(d)		255		136		20		41

Net regulatory asset related to income taxes^(e)		780		601		78		101		^(h	⁾
Accrued pension and post-retirement		1,616		680		211		316		^(b	⁾
ARO costs		133		133		—		—		2043
Regulatory transition charges (RTC)		3		—		3		—		2011
Gasification services agreement buyout costs		129		—		—		129		2018
Deferred debt expense^(e)		138		108		9		21		2040
Post-in-service carrying costs and deferred operating expense^(c)(l)		103		11		11		81		^(h	⁾
Under-recovery of fuel costs		21		20		1		—		2012
Hedge costs and other deferrals		6		—		6		—		^(b	⁾
Storm cost deferrals		33		—		21		12		^(b	⁾
Manufactured gas plant environmental costs		60		—		60		—		^(b	⁾
Smart Grid		28		—		28		—		^(b	⁾
RTO costs^(m)		7		—		7		—		^(b	⁾
Other		78		23		5		50		^(b	⁾

Total Non-Current Regulatory Assets		3,135		1,576		440		710
Total Regulatory Assets	$	3,390	$	1,712	$	460	$	751

Regulatory Liabilities^(a)
Nuclear property and insurance reserves	$	52	$	52	$	—	$	—		2011
DSM costs^(f)		38		38		—		—		⁽ⁱ	⁾
Gas purchase costs		25		—		25		—		2011
Over-recovery of fuel costs^(f)		155		152		3		—		2011
Other		9		5		2		2		^(b	⁾

Total Current Regulatory Liabilities^(g)		279		247		30		2

Removal costs^(e)		2,465		1,684		220		565		^(j	⁾
Nuclear property and liability reserves		89		89		—		—		2043
DSM costs^(f)		57		52		5		—		⁽ⁱ	⁾
Accrued pension and other post-retirement benefits		88		—		20		58		^(b	⁾
Commodity contract termination settlement		28		—		—		28		2014
Injuries and damages reserve^(e)		38		38		—		—		^(b	⁾
Hedge costs and other deferrals^(e)		75		60		1		—		2042
Other		36		17		19		—		^(b	⁾

Total Non-Current Regulatory Liabilities		2,876		1,940		265		651
Total Regulatory Liabilities	$	3,155	$	2,187	$	295	$	653

(a)	All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	Recovery/Refund period varies for these items with some currently unknown.

(c)	Duke Energy Carolinas is allowed to earn a return on the North Carolina portion of the outstanding balance. Duke Energy Carolinas does not earn a return on the South Carolina portion during the refund period.

(d)	Included in Other within Current Assets on the Consolidated Balance Sheets.

(e)	Included in rate base.

(f)	Duke Energy Carolinas is required to pay interest on the outstanding balance.

(g)	Included in Other within Current Liabilities and on the Consolidated Balance Sheets.

(h)	Recovery is over the life of the associated asset.

(i)	Incurred costs were deferred and are being recovered in rates. Duke Energy Carolinas is currently over-recovered for these costs in the South Carolina jurisdiction. For 2011 and 2010, expected refund period is three years and two years, respectively, but is dependent on volume of sales.

(j)	Liability is extinguished over the lives of the associated assets.

(k)	Represents the latest recovery period across all jurisdictions in which the Duke Energy Registrants operate. Regulatory asset and liability balances may be collected or refunded sooner than the indicated date in certain jurisdictions.

(l)	Duke Energy Carolinas amounts are excluded from rate base. Duke Energy Ohio amounts are included in rate base. At Duke Energy Indiana, some amounts are included and some are excluded from rate base.

(m)	Duke 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. (Midwest ISO).

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 PUCO, the KPSC, the PSCSC, the IURC and the NCUC imposed conditions (the 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. 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. Additionally, the Merger Conditions imposed the following restrictions on the ability of the public utility subsidiaries to pay cash dividends:

Duke Energy Carolinas. Under the 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.

Duke Energy Ohio. Under the 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 September 2009, the PUCO approved Duke Energy Ohio's request to pay dividends out of paid-in capital up to the amount of the pre-merger retained earnings and to maintain a minimum of 30% equity in its capital structure. 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.

Duke Energy Indiana. Under the 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.

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.

The following table includes information regarding the Subsidiary Registrants and other Duke Energy subsidiaries' restricted net assets at December 31, 2011.

Duke
Energy
Carolinas

Duke
Energy
Ohio^(a)

Duke
Energy
Indiana

Total
Duke
Energy
Subsidiaries

(in billions)

Amounts that may not be transferred to Duke Energy without appropriate approval based on above mentioned Merger Conditions

$

3.3

$

3.9

$

1.3

$

8.6

(a)	As of December 31, 2011, the equity balance available for payment of dividends, based on the FERC and PUCO order discussed above, was $1.2 billion.

Rate Related Information. The NCUC, PSCSC, IURC, PUCO and KPSC approve rates for retail electric and gas services within their states. Non-regulated 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.

Duke Energy Ohio Standard Service Offer (SSO). Ohio law provides the PUCO authority to approve an electric utility's generation SSO. A SSO may include an ESP, which would allow for the pricing structures used by Duke Energy Ohio from 2004 through 2011, or a Market Rate Offer (MRO), in which pricing is determined through a competitive bidding process. On November 15, 2010, Duke Energy Ohio filed for approval of an SSO to replace the then existing ESP that expired on December 31, 2011. The filing requested approval of a MRO. On February 23, 2011, the PUCO stated that Duke Energy Ohio did not file an application for a five-year MRO as required under Ohio statute. On June 20, 2011, Duke Energy Ohio filed an application with the PUCO for approval of an ESP for its customers beginning January 1, 2012, with rates in effect through May 31, 2021.

The PUCO approved Duke Energy Ohio's new ESP on November 22, 2011. The ESP includes competitive auctions for electricity supply for a term of January 1, 2012 through May 31, 2015. 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 and requires Duke Energy Ohio to transfer its generation assets to a non-regulated affiliate on or before December 31, 2014. Duke Energy Ohio conducted initial auctions on December 14, 2011 to serve SSO customers effective January 1, 2012. New rates for Duke Energy Ohio went into effect for SSO customers on January 1, 2012. 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.

The ESP effectively separates the generation of electricity from Duke Energy Ohio's retail load obligation. As a result Duke Energy Ohio's generation assets no longer serve retail load customers or receive negotiated pricing under the ESP. The generation assets began dispatching all of their electricity into unregulated markets in January 2012. Duke Energy Ohio's retail load obligation is satisfied through competitive auctions, the costs of which are recovered from customers. As a result, Duke Energy Ohio earns margin on the transmission and distribution of electricity only and not on the cost of the underlying energy.

Duke Energy Carolinas North Carolina Rate Case. On July 1, 2011, Duke Energy Carolinas filed a rate case with the NCUC to request an average 15% increase in retail revenues, or approximately $646 million, with a rate of return on equity of 11.5%. The increase is designed to recover the cost of the ongoing generation fleet modernization program, environmental compliance and other capital investments made since 2009.

On November 22, 2011, Duke Energy Carolinas entered into a settlement agreement with 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 beginning in February 2012. The proposed settlement includes a 10.5% return on equity and a capital structure of 53% equity and 47% long-term debt. In order to mitigate the impact of the increase on customers, the agreement provides for (i) Duke Energy to waive its right to increase the amount of construction work in progress in rate base for any expenditures associated with Cliffside Unit 6 above the North Carolina retail portion included in the 2009 North Carolina Rate Case, (ii) the accelerated return of certain regulatory liabilities, related to accumulated EPA sulfur dioxide auction proceeds, to customers, which lowered the total impact to customer bills to an increase of approximately 7.2% in the near-term; and (iii) a one-time $11 million shareholder contribution to agencies that provide energy assistance to low income customers. In exchange for waiving the right to increase the amount of construction work in process for Cliffside Unit 6, Duke Energy will continue to capitalize AFUDC on all expenditures associated with Cliffside Unit 6 not included in rate base as a result of the 2009 North Carolina Rate Case.

The NCUC approved the settlement agreement in full by order dated January 27, 2012.

Duke Energy Carolinas South Carolina Rate Case. On August 5, 2011, Duke Energy Carolinas filed a rate case with the PSCSC to request an average 15% increase in retail revenues, or approximately $216 million, with a rate of return on equity of 11.5%. The increase is designed to recover the cost of the ongoing generation fleet modernization program, environmental compliance and other capital investments made since 2009.

On December 7, 2011, Duke Energy Carolinas filed a revised settlement agreement with the Office of Regulatory Staff (ORS), Wal-Mart Stores East, LP ("Wal-Mart"), and Sam's East, Inc ("Sam's"). The Commission of Public Works for the city of Spartanburg, S.C. and the Spartanburg Sanitary Sewer District were not parties to the agreement; however, 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 beginning February 6, 2012. The proposed settlement includes a 10.5% return on equity, a capital structure of 53% equity and 47% long-term debt, and a one-time contribution of $4 million to Advance SC.

The PSCSC approved the settlement agreement in full by order dated January 25, 2012.

Duke Energy Indiana Energy Efficiency. On September 28, 2010, Duke Energy Indiana filed a petition for new energy efficiency programs to enable meeting the IURC's energy efficiency mandates. Duke Energy Indiana's proposal requests recovery of costs through a rider including lost revenues and incentives for "core plus" energy efficiency programs and lost revenues and cost recovery for "core" energy efficiency programs. The hearing occurred in July 2011 and an order is expected in the first quarter of 2012.

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 Indiana Office of Utility Consumer Counselor (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. The IURC set a new procedural schedule to take supplemental testimony and an evidentiary hearing was held in June 2011. On October 19, 2011, the IURC issued an order denying Duke Energy Indiana the right to defer the storm expense discussed above. In November 2011, Duke Energy Indiana submitted notice of its intent to appeal the IURC order to the Indiana Court of Appeals.

Duke Energy Ohio Storm Cost Recovery. On December 11, 2009, Duke Energy Ohio filed an application with the PUCO to recover Hurricane Ike storm restoration costs of $31 million through a discrete rider. The PUCO granted the request to defer the costs associated with the storm recovery; however, they further ordered Duke Energy Ohio to file a separate action pursuant to which the actual amount of recovery would be determined. On January 11, 2011, the PUCO approved recovery of $14 million plus carrying costs which will be spread over a three-year period. Duke Energy Ohio filed an application for rehearing on February 10, 2011, as did the consumer advocate, the office of the Ohio Consumers' Council (OCC). On March 9, 2011, the PUCO denied the rehearing requests of Duke Energy Ohio and the OCC. Duke Energy Ohio filed a notice of appeal with the Ohio Supreme Court on May 6, 2011 and briefs have been filed by Duke Energy Ohio and the PUCO. Oral arguments were held on February 7, 2012. A decision by the Ohio Supreme Court is forthcoming.

Capital Expansion Projects.

Overview. USFE&G is engaged in planning efforts to meet projected load growth in its service territories. Capacity additions may include new nuclear, IGCC, coal facilities or gas-fired generation units. Because of the long lead times required to develop such assets, USFE&G is taking steps now to ensure those options are available.

Duke Energy Carolinas 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 allowed Duke Energy to incur project development and pre-construction costs for the project through June 30, 2012, and up to an aggregate maximum amount of $350 million.

As a condition to the approval of continued development of the project, Duke Energy Carolinas shall provide certain monthly reports to the PSCSC and the ORS. Duke Energy Carolinas has also agreed to provide a monthly report to certain parties on the progress of negotiations to acquire an interest in the V.C. Summer Nuclear Station (refer to discussion below) expansion being developed by South Carolina Public Service Authority (Santee Cooper) and South Carolina Electric & Gas Company (SCE&G). Any change in ownership interest, output allocation, sharing of costs or control and any future option agreements concerning Lee Nuclear Station shall be subject to prior approval of the PSCSC.

The NRC review of the COL application continues and the estimated receipt of the COL is in mid 2013. Duke Energy Carolinas filed with the Department of Energy (DOE) for a federal loan guarantee, which has the potential to significantly lower financing costs associated with the proposed Lee Nuclear Station; however, it was not among the four projects selected by the DOE for the final phase of due diligence for the federal loan guarantee program. The project could be selected in the future if the program funding is expanded or if any of the current finalists drop out of the program.

Duke Energy Carolinas is seeking partners for Lee Nuclear Station by issuing options to purchase an ownership interest in the plant. In the first quarter of 2011, Duke Energy Carolinas entered into an agreement with JEA that provides JEA with an option to purchase up to a 20% undivided ownership interest in Lee Nuclear Station. JEA has 90 days following Duke Energy Carolinas' receipt of the COL to exercise the option.

Duke Energy Carolinas 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 five percent to ten percent ownership interest in the V.C. Summer Nuclear Station being developed by Santee Cooper and SCE&G near Jenkinsville, South Carolina. The letter of intent 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.

Duke Energy Carolinas 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 is expected to have 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 the approved new 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. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by $125 million in federal advanced clean coal tax credits, as discussed in Note 5. Cliffside Unit 6 is expected to begin operation by the end of 2012. Also, see Note 5 for information related to the Cliffside Unit 6 air permit.

Duke Energy Carolinas Dan River and Buck Combined Cycle Facilities. 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 each of Duke Energy Carolinas' existing Dan River Steam Station and Buck Steam Station. The Division of Air Quality (DAQ) issued a final air permit authorizing construction of the Buck and Dan River combined cycle natural gas-fired generating units in October 2008 and August 2009, respectively.

In November 2011, Duke Energy Carolinas placed its 620 MW Buck combined cycle natural gas-fired generation facility in service. This is the first of Duke Energy's key modernization projects to be commissioned. The Dan River project is expected to begin operation by the end of 2012. Based on the most updated cost estimates, total costs (including AFUDC) for the Buck and Dan River projects are $700 million and $716 million, respectively.

Duke Energy Indiana Edwardsport IGCC Plant. On September 7, 2006, Duke Energy Indiana and Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana (Vectren) filed a joint petition with the IURC seeking a CPCN for the construction of a 618 MW IGCC power plant at Duke Energy Indiana's Edwardsport Generating Station in Knox County, Indiana. The facility was initially estimated to cost approximately $1.985 billion (including $120 million of AFUDC). In August 2007, Vectren formally withdrew its participation in the IGCC plant and a hearing was conducted on the CPCN petition based on Duke Energy Indiana owning 100% of the project. On November 20, 2007, the IURC issued an order granting Duke Energy Indiana a CPCN for the proposed IGCC project, approved the cost estimate of $1.985 billion and approved the 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 approves the implementation of an updated IGCC rider to recover costs incurred through September 30, 2009, effective immediately. The approvals are 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 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 Goodwill and other impairment charges on Duke Energy's Consolidated Statement of Operations. This charge is recorded in Impairment charges on Duke Energy Indiana's Consolidated Statements of Operations. Due to the IURC investigation discussed below, 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 are set for April 24, 2012 and April 25, 2012, respectively.

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 will lower the overall customer rate increase related to the project from an average of 19% to approximately 16%. The proposal is subject to the approval of the IURC in the Phase I hearings.

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 eight semi-annual rider requests are scheduled for August 6-7, 2012.

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 parties recommended that recovery be limited to the costs incurred on the IGCC project as of November 30, 2009 (Duke Energy Indiana estimates it had committed costs of $1.6 billion), with further IURC proceedings to be held to determine the financial consequences of this recommendation.

On October 19, 2011, Duke Energy 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 a pre-tax impairment charge of approximately $44 million recorded in the third quarter of 2010 as discussed above. These charges are recorded in Goodwill and other impairment charges on Duke Energy's Consolidated Statement of Operations, and in Impairment charges on Duke Energy Indiana's Consolidated Statements of Operations. The cost cap, if approved by the IURC, limits the amount of project construction costs that may be incorporated into customer rates in Indiana. As a result of the proposed cost cap, recovery of these cost increases is not considered probable. Additional updates to the cost estimate could occur through the completion of the plant in 2012.

Phase I and Phase II hearings concluded on January 24, 2012. Final orders from the IURC on Phase I and Phase II of the subdocket and the pending IGCC rider proceedings are expected no sooner than the end of the third quarter 2012.

Duke Energy is unable to predict the ultimate outcome of these proceedings. In the event the IURC disallows a portion of the plant costs, including financing costs, or if cost estimates for the plant increase, additional charges to expense, which could be material, could occur. Construction of the Edwardsport IGCC plant is ongoing and is currently expected to be completed and placed in-service in 2012.

Duke Energy Indiana Carbon Sequestration. Duke Energy Indiana filed a petition with the IURC requesting approval of its plans for studying carbon storage, sequestration and/or enhanced oil recovery for the carbon dioxide (CO₂) from the Edwardsport IGCC facility on March 6, 2009. On July 7, 2009, Duke Energy Indiana filed its case-in-chief testimony requesting approval for cost recovery of a $121 million site assessment and characterization plan for CO₂ sequestration options including deep saline sequestration, depleted oil and gas sequestration and enhanced oil recovery for the CO₂ from the Edwardsport IGCC facility. The OUCC filed testimony supportive of the continuing study of carbon storage, but recommended that Duke Energy Indiana break its plan into phases, recommending approval of only $33 million in expenditures at this time and deferral of expenditures rather than cost recovery through a tracking mechanism as proposed by Duke Energy Indiana. The CAC, an intervenor, recommended against approval of the carbon storage plan stating customers should not be required to pay for research and development costs. Duke Energy Indiana's rebuttal testimony was filed October 30, 2009, wherein it amended its request to seek deferral of $42 million to cover the carbon storage site assessment and characterization activities scheduled to occur through the end of 2010, with further required study expenditures subject to future IURC proceedings. An evidentiary hearing was held on November 9, 2009.

Duke Energy Indiana IURC Investigation. On October 5, 2010, the Governor of Indiana terminated the employment of the Chairman of the IURC in connection with Duke Energy Indiana's hiring of an attorney from the IURC staff. As requested by the governor, the Indiana Inspector General initiated an investigation into whether the IURC attorney violated any state ethics rules, and the IURC announced it would internally audit the Duke Energy Indiana cases dating from January 1, 2010 through September 30, 2010, on which this attorney worked while at the IURC, which includes the Indiana storm costs deferral request discussed above, as well as all Edwardsport IGCC cases dating back to 2006. Duke Energy Indiana engaged an outside law firm to conduct its own investigation regarding Duke Energy Indiana's hiring of an IURC attorney and Duke Energy Indiana's related hiring practices. On October 5, 2010, Duke Energy Indiana placed the attorney and President of Duke Energy Indiana on administrative leave. They were subsequently terminated on November 8, 2010. On December 7, 2010, the IURC released its internal audit findings concluding that the previous rulings were supported by sound, legal reasoning consistent with the Indiana Rules of Evidence and historical practice and procedures of the IURC and that the previous rulings appeared to be balanced and consistent among the parties. The audit concluded it did not reveal any bias or a resultant unfair advantage obtained by Duke Energy Indiana as a result of the evidentiary rulings of the former IURC attorney. As noted above, in the storm cost deferral case, the IURC found no conflict between the order and the staff report; however, the audit report noted the staff report offered no specific recommendation to either approve or deny the requested relief and that this was the only order that was subject to an appeal. As such, the IURC reopened that proceeding for further review and consideration of the evidence presented. The Inspector General's investigation into whether the former IURC attorney violated any state ethics rules was the subject of an Indiana Ethics Commission hearing that was held on April 14, 2011, and a final report was issued on May 14, 2011. The final report pertained only to the conduct of the former IURC attorney as Duke Energy Indiana was not a subject of the investigation.

Potential Plant Retirements.

Duke Energy Generating Facility Retirements. Duke Energy Carolinas, Duke Energy Indiana, Duke Energy Ohio and Duke Energy Kentucky each 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 Duke Energy Carolinas, Duke Energy Indiana, Duke Energy Ohio and Duke Energy Kentucky in 2011 and 2010 included planning assumptions to potentially retire by 2015, certain coal-fired generating facilities in North Carolina, South Carolina, Indiana, Ohio and Kentucky that do not have the requisite emission control equipment, primarily to meet EPA regulations that are not yet effective. The table below contains, as of December 31, 2011, the net carrying value of these facilities that are in the Consolidated Balance Sheets.


	Duke Energy		Duke Energy Carolinas^(a)		Duke Energy Ohio^(b)(e)		Duke Energy Indiana^(c)
MW		3,329		1,356		1,025		948
Remaining net book value (in millions)^(d)	$	353	$	199	$	14	$	140
Remaining non-current regulatory asset^(f)	$	73	$	—	$	—	$	73

(a)

Includes Dan River, Riverbend, Lee 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 311 MW have already been retired as of December 31, 2011. See Note 5 for additional information related to the Cliffside air permit.

(b)	Includes Beckjord and Miami Fort unit 6.

(c)	Includes Wabash River units 2-6 and Gallagher units 1 and 3.

(d)	Included in Property, plant and equipment, net as of December 31, 2011, on the Consolidated Balance Sheets.

(e)	Beckjord has no remaining net book value – See Note 12 for additional information.

(f)

On February 1, 2012, 280 MW for Gallagher units 1 and 3 were retired by Duke Energy Indiana. In its December 28, 2011 order, the IURC allowed recovery of and return on the carrying value of the Gallagher units over the original life of these units and classification of this amount as a regulatory asset.

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.

Other Matters.

Duke Energy Ohio and Duke Energy Kentucky 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 the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) to PJM, effective December 31, 2011.

On December 16, 2010, FERC issued an order related to the Midwest ISO's cost allocation methodology surrounding Multi-Value Projects (MVP), a type of Midwest ISO Transmission Expansion Planning (MTEP) project cost. The Midwest ISO 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 Midwest ISO footprint. The Midwest ISO approved MVP proposals with estimated project costs of approximately $5.2 billion prior to the date of Duke Energy Ohio's exit from the Midwest ISO on December 31, 2011. These projects are expected to be undertaken by the constructing transmission owners from 2012 through 2020 with costs recovered through the Midwest ISO over the useful life of the projects. The FERC order did not clearly and expressly approve the Midwest ISO's apparent interpretation that a withdrawing transmission owner is obligated to pay its share of costs of all MVP projects approved by the Midwest ISO up to the date of the withdrawing transmission owners' exit from the Midwest ISO. Duke Energy Ohio, including Duke Energy Kentucky, has historically represented approximately five-percent of the Midwest ISO system. The impact of this order is not fully known, but could result in a substantial increase in the Midwest ISO transmission expansion costs allocated to Duke Energy Ohio and Duke Energy Kentucky subsequent to a withdrawal from the Midwest ISO. Duke Energy Ohio and Duke Energy Kentucky, 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 Midwest ISO'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 will 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 and Duke Energy Kentucky's challenge of the Midwest ISO's ability to allocate MVP costs to a withdrawing transmission owner is beyond the scope of the proceeding. The Order further stated that Midwest ISO'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 their rights, Duke Energy Ohio and Duke Energy Kentucky 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.

Duke Energy Ohio and Duke Energy Kentucky have entered into settlements or have received state regulatory approvals associated with the RTO realignment if ultimately allocated to Duke Energy Ohio and Duke Energy Kentucky. On December 22, 2010, the KPSC issued an order granting approval of Duke Energy Kentucky's request to effect the RTO realignment, subject to several conditions. The conditions accepted by Duke Energy Kentucky include a commitment to not seek to double-recover in a future rate case the transmission expansion fees that may be charged by the Midwest ISO and PJM in the same period or overlapping periods. On January 25, 2011, the KPSC issued an order stating that the order had been satisfied and is now unconditional.

On April 26, 2011, Duke Energy Ohio, Ohio Energy Group, The Office of Ohio Consumers' Counsel and the Commission Staff filed an Application and a Stipulation with the PUCO regarding Duke Energy Ohio's recovery via a non-bypassable rider of certain costs related to its proposed RTO realignment. Under the Stipulation, Duke Energy Ohio would recover all MTEP costs, including but not limited to MVP costs, directly or indirectly charged to Duke Energy Ohio retail customers. Duke Energy Ohio would not seek to recover any portion of the Midwest ISO 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 Midwest ISO. On May 25, 2011, the Stipulation was approved by the PUCO. An application for rehearing filed by Ohio Partners for Affordable Energy was denied by the PUCO on July 15, 2011.

On October 14, 2011, Duke Energy Ohio and Duke Energy Kentucky 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 and Duke Energy Kentucky are seeking recovery of their legacy MTEP costs. The new rates went into effect, subject to refund, on January 1, 2012. Protests were filed by certain transmission customers. The matter is pending response from FERC.

On November 2, 2011, the Midwest ISO, the Midwest ISO Transmission Owners, Duke Energy Ohio and Duke Energy Kentucky jointly submitted to the FERC a filing that addresses the treatment of MTEP costs, excluding MVP costs. The November 2, 2011 filing, which was accepted by the FERC on December 30, 2011, provides that the MISO Transmission Owners will continue to be obligated to construct the non-MVP MTEP projects, for which Duke Energy Ohio and Duke Energy Kentucky will continue to be obligated to pay a portion of the costs. Likewise, transmission customers serving load in the Midwest ISO will continue to be obligated to pay a portion of the costs of a previously identified non-MVP MTEP project that Duke Energy Ohio has constructed.

On December 29, 2011, Midwest ISO filed with FERC a Schedule 39 to the Midwest ISO'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 the Midwest ISO, or, if the owner fails to report such load, based on the owner's historical usage in the Midwest ISO assuming annual load growth. On January 19, 2012, Duke Energy Ohio and Duke Energy Kentucky filed with FERC a protest of the allocation of MVP costs to them under Schedule 39.

On December 31, 2011, Duke Energy Ohio recorded a liability for its Midwest ISO 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 sheet upon exit from the Midwest ISO 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 statement of operations. In addition to the above amounts, Duke Energy Ohio may also be responsible for costs associated with the Midwest ISO 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.

Regulatory Matters

4. Regulatory Matters

Regulatory Assets and Liabilities.

As of December 31, 2011 and 2010, the substantial majority of USFE&G's operations applied regulatory accounting treatment. From 2009 through 2011, certain portions of Commercial Power's operations applied regulatory accounting treatment; however, effective November 2011, as a result of the new Electric Security Plan (ESP), regulatory accounting treatment will no longer be applied. 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.

Duke Energy Registrants' Regulatory Assets and Liabilities:


As of December 31, 2011	Duke Energy		Duke Energy Carolinas		Duke Energy Ohio		Duke Energy Indiana		Recovery/Refund Period Ends^(k)
	(in millions)
Regulatory Assets^(a)
Vacation accrual	$	150	$	70	$	7	$	13		2012
Under-recovery of fuel costs		38		—		10		28		2012
Hedge costs and other deferrals		4		3		1		—		2012
Post-in-service carrying costs and deferred operating expense^(c)(l)		31		28		—		3		2012
Over-distribution of Bulk Power Marketing sharing		41		41		—		—		2012
Demand side management costs (DSM costs)/Energy Efficiency		43		25		—		18		2012
Regional Transmission Organization (RTO) costs^(m)		17		5		—		12		2012
SmartGrid		9		—		9		—		2012
Gasification services agreement buyout costs		25		—		—		25		2012
Other		16		—		1		15		2012

Total Current Regulatory Assets^(d)		374		172		28		114


Net regulatory asset related to income taxes^(e)		892		668		77		147		^(h	⁾
Accrued pension and post-retirement		1,726		734		212		314		^(b	⁾
ARO costs		191		191		—		—		2043
Gasification services agreement buyout costs		88		—		—		88		2018
Deferred debt expense^(e)		122		98		8		16		2041
Post-in-service carrying costs and deferred operating expense^(c)(l)		119		31		16		72		^(h	⁾
Under-recovery of fuel costs		13		13		—		—		2013
Hedge costs and other deferrals		166		91		8		67		^(b	⁾
Storm cost deferrals		18		—		18		—		^(b	⁾
Manufactured gas plant environmental costs		69		—		69		—		^(b	⁾
Smart Grid		32		—		32		—		^(b	⁾
Gallagher Units 1 & 3		73		—		—		73		^(b	⁾
RTO costs^(m)		80		13		74		—		^(b	⁾
DSM costs/Energy Efficiency		38		38		—		—		^(b	⁾
Other		45		17		6		21		^(b	⁾

Total Non-Current Regulatory Assets		3,672		1,894		520		798

Total Regulatory Assets	$	4,046	$	2,066	$	548	$	912

Regulatory Liabilities^(a)
Nuclear property and insurance reserves	$	2	$	2	$	—	$	—		2012
DSM costs^(f)		41		41		—		—		2012
Gas purchase costs		20		—		20		—		2012
Over-recovery of fuel costs^(f)		6		6		—		—		2012
Other		18		13		2		3		2012

Total Current Regulatory Liabilities^(g)		87		62		22		3


Removal costs^(e)		2,586		1,770		230		590		^(j	⁾
Nuclear property and liability reserves		86		86		—		—		2043
DSM costs^(f)/Energy Efficiency		27		10		17		—		⁽ⁱ	⁾
Accrued pension and other post-retirement benefits		117		—		19		70		^(b	⁾
Commodity contract termination settlement		23		—		—		23		2014
Injuries and damages reserve^(e)		38		38		—		—		^(b	⁾
Hedge costs and other deferrals^(e)		12		—		—		—		2016
Other		30		24		7		—		^(b	⁾

Total Non-Current Regulatory Liabilities		2,919		1,928		273		683

Total Regulatory Liabilities	$	3,006	$	1,990	$	295	$	686


As of December 31, 2010	Duke Energy		Duke Energy Carolinas		Duke Energy Ohio		Duke Energy Indiana		Recovery/Refund Period Ends^(k)
	(in millions)
Regulatory Assets^(a)
Vacation accrual	$	146	$	67	$	8	$	13		2011
Under-recovery of fuel costs		31		—		12		19		2011
Post-in-service carrying costs and deferred operating expense^(c)(l)		28		28		—		—		2011
Over-distribution of Bulk Power Marketing sharing		35		35		—		—		2011
Other		15		6		—		9		2011

Total Current Regulatory Assets^(d)		255		136		20		41

Net regulatory asset related to income taxes^(e)		780		601		78		101		^(h	⁾
Accrued pension and post-retirement		1,616		680		211		316		^(b	⁾
ARO costs		133		133		—		—		2043
Regulatory transition charges (RTC)		3		—		3		—		2011
Gasification services agreement buyout costs		129		—		—		129		2018
Deferred debt expense^(e)		138		108		9		21		2040
Post-in-service carrying costs and deferred operating expense^(c)(l)		103		11		11		81		^(h	⁾
Under-recovery of fuel costs		21		20		1		—		2012
Hedge costs and other deferrals		6		—		6		—		^(b	⁾
Storm cost deferrals		33		—		21		12		^(b	⁾
Manufactured gas plant environmental costs		60		—		60		—		^(b	⁾
Smart Grid		28		—		28		—		^(b	⁾
RTO costs^(m)		7		—		7		—		^(b	⁾
Other		78		23		5		50		^(b	⁾

Total Non-Current Regulatory Assets		3,135		1,576		440		710
Total Regulatory Assets	$	3,390	$	1,712	$	460	$	751

Regulatory Liabilities^(a)
Nuclear property and insurance reserves	$	52	$	52	$	—	$	—		2011
DSM costs^(f)		38		38		—		—		⁽ⁱ	⁾
Gas purchase costs		25		—		25		—		2011
Over-recovery of fuel costs^(f)		155		152		3		—		2011
Other		9		5		2		2		^(b	⁾

Total Current Regulatory Liabilities^(g)		279		247		30		2

Removal costs^(e)		2,465		1,684		220		565		^(j	⁾
Nuclear property and liability reserves		89		89		—		—		2043
DSM costs^(f)		57		52		5		—		⁽ⁱ	⁾
Accrued pension and other post-retirement benefits		88		—		20		58		^(b	⁾
Commodity contract termination settlement		28		—		—		28		2014
Injuries and damages reserve^(e)		38		38		—		—		^(b	⁾
Hedge costs and other deferrals^(e)		75		60		1		—		2042
Other		36		17		19		—		^(b	⁾

Total Non-Current Regulatory Liabilities		2,876		1,940		265		651
Total Regulatory Liabilities	$	3,155	$	2,187	$	295	$	653

(a)	All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b)	Recovery/Refund period varies for these items with some currently unknown.

(c)	Duke Energy Carolinas is allowed to earn a return on the North Carolina portion of the outstanding balance. Duke Energy Carolinas does not earn a return on the South Carolina portion during the refund period.

(d)	Included in Other within Current Assets on the Consolidated Balance Sheets.

(e)	Included in rate base.

(f)	Duke Energy Carolinas is required to pay interest on the outstanding balance.

(g)	Included in Other within Current Liabilities and on the Consolidated Balance Sheets.

(h)	Recovery is over the life of the associated asset.

(i)	Incurred costs were deferred and are being recovered in rates. Duke Energy Carolinas is currently over-recovered for these costs in the South Carolina jurisdiction. For 2011 and 2010, expected refund period is three years and two years, respectively, but is dependent on volume of sales.

(j)	Liability is extinguished over the lives of the associated assets.

(k)	Represents the latest recovery period across all jurisdictions in which the Duke Energy Registrants operate. Regulatory asset and liability balances may be collected or refunded sooner than the indicated date in certain jurisdictions.

(l)	Duke Energy Carolinas amounts are excluded from rate base. Duke Energy Ohio amounts are included in rate base. At Duke Energy Indiana, some amounts are included and some are excluded from rate base.

(m)	Duke 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. (Midwest ISO).

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 PUCO, the KPSC, the PSCSC, the IURC and the NCUC imposed conditions (the 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. 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. Additionally, the Merger Conditions imposed the following restrictions on the ability of the public utility subsidiaries to pay cash dividends:

Duke Energy Carolinas. Under the 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.

Duke Energy Ohio. Under the 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 September 2009, the PUCO approved Duke Energy Ohio's request to pay dividends out of paid-in capital up to the amount of the pre-merger retained earnings and to maintain a minimum of 30% equity in its capital structure. 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.

Duke Energy Indiana. Under the 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.

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.

The following table includes information regarding the Subsidiary Registrants and other Duke Energy subsidiaries' restricted net assets at December 31, 2011.

Duke
Energy
Carolinas

Duke
Energy
Ohio^(a)

Duke
Energy
Indiana

Total
Duke
Energy
Subsidiaries

(in billions)

Amounts that may not be transferred to Duke Energy without appropriate approval based on above mentioned Merger Conditions

$

3.3

$

3.9

$

1.3

$

8.6

(a)	As of December 31, 2011, the equity balance available for payment of dividends, based on the FERC and PUCO order discussed above, was $1.2 billion.