REGULATORY MATTERS

Regulatory Assets and Liabilities

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

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



	December 31, 2014
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Asset retirement obligations	$	3,017	$	907	$	1,882	$	1,584	$	298	$	—	$	—
Accrued pension and OPEB	2,015		412		812		354		458		132		217
Retired generation facilities	1,659		58		1,545		152		1,393		—		56
Debt fair value adjustment	1,305		—		—		—		—		—		—
Net regulatory asset related to income taxes	1,144		614		354		141		213		64		111
Hedge costs and other deferrals	628		103		490		217		273		7		28
Demand side management (DSM)/Energy efficiency (EE)	330		106		203		193		10		21		—
Grid Modernization	76		—		—		—		—		76		—
Vacation accrual	213		86		46		46		—		6		12
Deferred fuel	246		50		182		138		44		9		5
Nuclear deferral	296		141		155		43		112		—		—
Post-in-service carrying costs and deferred operating expenses	494		124		121		28		93		21		228
Gasification services agreement buyout	55		—		—		—		—		—		55
Transmission expansion obligation	70		—		—		—		—		74		—
Manufactured gas plant (MGP)	115		—		—		—		—		115		—
Other	494		263		109		66		42		36		66
Total regulatory assets	12,157		2,864		5,899		2,962		2,936		561		778
Less: current portion	1,115		399		491		287		203		49		93
Total non-current regulatory assets	$	11,042	$	2,465	$	5,408	$	2,675	$	2,733	$	512	$	685



	December 31, 2014
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Liabilities
Costs of removal	$	5,221	$	2,420	$	1,975	$	1,692	$	283	$	222	$	613
Amounts to be refunded to customers	166		—		70		—		70		—		96
Storm reserve	150		25		125		—		125		—		—
Accrued pension and OPEB	379		76		121		61		60		19		91
Deferred fuel	37		6		23		23		—		—		8
Other	444		217		171		127		44		10		42
Total regulatory liabilities	6,397		2,744		2,485		1,903		582		251		850
Less: current portion	204		34		106		71		35		10		54
Total non-current regulatory liabilities	$	6,193	$	2,710	$	2,379	$	1,832	$	547	$	241	$	796



	December 31, 2013
(in millions)	Duke Energy		Duke Energy Carolinas		Progress Energy		Duke Energy Progress		Duke Energy Florida		Duke Energy Ohio		Duke Energy Indiana
Regulatory Assets
Asset retirement obligations	$	1,608	$	123	786		$	389	$	397	$	—	$	—
Accrued pension and OPEB	1,723		347		750		269		438		120		219
Retired generation facilities	1,748		68		1,619		241		1,378		—		61
Debt fair value adjustment	1,338		—		—		—		—		—		—
Net regulatory asset related to income taxes	1,115		555		331		113		218		72		157
Hedge costs and other deferrals	450		98		318		165		153		5		29
DSM/EE	306		140		152		140		12		14		—
Grid Modernization	65		—		—		—		—		65		—
Vacation accrual	210		82		55		50		—		7		13
Deferred fuel	94		—		37		6		31		14		43
Nuclear deferral	262		40		222		77		145		—		—
Post-in-service carrying costs and deferred operating expenses	459		150		137		19		118		21		151
Gasification services agreement buyout	75		—		—		—		—		—		75
Transmission expansion obligation	70		—		—		—		—		74		—
MGP	90		—		—		—		—		90		—
Other	473		219		101		42		60		46		87
Total regulatory assets	10,086		1,822		4,508		1,511		2,950		528		835
Less: current portion	895		295		353		127		221		57		118
Total non-current regulatory assets	$	9,191	$	1,527	$	4,155	$	1,384	$	2,729	$	471	$	717



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

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

Asset retirement obligations. Represents legal obligations associated with the future retirement of property, plant and equipment. Asset retirement obligations relate primarily to decommissioning nuclear power facilities and closure of ash basins in North Carolina and South Carolina. No return is currently earned on these balances. The recovery period for costs related to nuclear facilities runs through the decommissioning period of each nuclear unit, the latest of which is currently estimated to be 2097. The recovery period for costs related to ash basin closures has not yet been determined. See Notes 1 and 9 for additional information.

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

Retired generation facilities. Duke Energy Florida earns a reduced return on a substantial portion of the amount of regulatory asset associated with the retirement of Crystal River Unit 3 not included in rate base and a full return on a portion of the retired plant currently recovered in the nuclear cost recovery clause (NCRC). Once included in base rates the amount will be amortized over 20 years. Duke Energy Carolinas earns a return on the outstanding retail balance with recovery periods ranging from 5 to 10 years. Duke Energy Progress earns a return on the outstanding balance with recovery over a period of 10 years for retail purposes and over the longer of 10 years or the previously estimated planned retirement date for wholesale purposes. Duke Energy Indiana earns a return on the outstanding balances and the costs are included in rate base.

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

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

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

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

Grid Modernization. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service. Recovery period is generally one year for depreciation and operating expenses. Recovery for post-in-service carrying costs are over the life of the assets.

Vacation accrual. Generally recovered within one year.

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

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

Post-in-service carrying costs and deferred operating expenses. Represents deferred depreciation and operating expenses as well as carrying costs on the portion of capital expenditures placed in service but not yet reflected in retail rates as plant in service. Duke Energy Carolinas, Duke Energy Progress, Duke Energy Ohio and Duke Energy Indiana earn a return on the outstanding balance. Duke Energy Florida earns a return at a reduced rate. For Duke Energy Ohio and Duke Energy Indiana, some amounts are included in rate base. Recovery is over various lives, and the latest recovery period is 2081.

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

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

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

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

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

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

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

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

Duke Energy Progress and Duke Energy Florida also have restrictions imposed by their first mortgage bond indentures and Articles of Incorporation which, in certain circumstances, limit 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, 2014.

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

Duke Energy Carolinas

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

Duke Energy Progress

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

Duke Energy Ohio

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

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

Duke Energy Indiana

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

The restrictions discussed above were less than 25 percent of Duke Energy's net assets at December 31, 2014.

Rate Related Information

The NCUC, PSCSC, FPSC, IURC, PUCO and KPSC approve rates for retail electric and natural gas services within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates (excluding Ohio and Indiana), as well as sales of transmission service.

Duke Energy Carolinas

2013 North Carolina Rate Case

On September 24, 2013, the NCUC approved a settlement agreement related to Duke Energy Carolinas’ request for a rate increase with minor modifications. The NCUC Public Staff (Public Staff) was a party to the settlement. The settling parties agreed to a three-year step-in rate increase, with the first two years providing for $204 million, or a 4.5 percent average increase in rates, and the third year providing for rates to be increased by an additional $30 million, or 0.6 percent. The agreement is based upon a return on equity of 10.2 percent and an equity component of the capital structure of 53 percent. The settlement agreement (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $10 million shareholder contribution to agencies that provide energy assistance to low-income customers, and (iii) an annual reduction in the regulatory liability for costs of removal of $30 million for each of the first two years. Duke Energy Carolinas has agreed not to request additional base rate increases to be effective before September 2015. New rates went into effect on September 25, 2013.

On October 23, 2013, the North Carolina Attorney General (NCAG) appealed the rate of return and capital structure approved in the agreement. The NC Waste Awareness and Reduction Network (NC WARN) appealed various matters in the settlement on October 24, 2013. The North Carolina Supreme Court (NCSC) denied a motion to consolidate these appeals with other North Carolina rate case appeals involving Duke Energy Carolinas and Duke Energy Progress on March 13, 2014. Briefing concluded in this matter and oral argument occurred on September 8, 2014. On January 23, 2015, the NCSC affirmed the NCUC's September 24, 2013 order.

2013 South Carolina Rate Case

On September 11, 2013, the PSCSC approved a settlement agreement related to Duke Energy Carolinas’ request for a rate increase. Parties to the settlement agreement were the Office of Regulatory Staff, Wal-Mart Stores East, LP and Sam’s East, Incorporated, the South Carolina Energy Users Committee, Public Works of the City of Spartanburg, South Carolina and the South Carolina Small Business Chamber of Commerce. The parties agreed to a two-year step-in rate increase, with the first year providing for approximately $80 million, or a 5.5 percent average increase in rates, and the second year providing for rates to be increased by an additional $38 million, or 2.6 percent. The settlement agreement is based upon a return on equity of 10.2 percent and a 53 percent equity component of the capital structure. The settlement agreement (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) approximately $4 million of contributions to agencies that provide energy assistance to low-income customers and for economic development, and (iii) a reduction in the regulatory liability for costs of removal of $45 million for the first year. Duke Energy Carolinas has agreed not to request additional base rate increases to be effective before September 2015. New rates went into effect on September 18, 2013.

2011 North Carolina Rate Case

On January 27, 2012, the NCUC approved a settlement agreement related to Duke Energy Carolinas’ request for a rate increase. On October 23, 2013, the NCUC issued a second order in the case reaffirming the rate of return approved in the settlement agreement, in response to an appeal by the NCAG. On November 21, 2013, the NCAG appealed the NCUC's October 2013 order. On December 19, 2014, the NCSC affirmed the NCUC's October 2013 order concluding the appeal.

William States Lee Combined Cycle Facility

On April 9, 2014, the PSCSC granted Duke Energy Carolinas and NCEMC a Certificate of Environmental Compatibility and Public Convenience and Necessity (CECPCN) for the construction and operation of a 750 MW combined cycle natural gas-fired generating plant at its existing William States Lee Generating Station in Anderson, South Carolina. On May 16, 2014, Duke Energy Carolinas announced its intention to begin construction in summer 2015 and estimated a cost to build of $600 million for its share of the facility, including AFUDC. The project is expected to be commercially available in late 2017. NCEMC will own approximately 13 percent of the project. On July 3, 2014, the South Carolina Coastal Conservation League and Southern Alliance for Clean Energy jointly filed a Notice of Appeal with the Court of Appeals of South Carolina seeking the court's review of the PSCSC's decision. Duke Energy Carolinas' initial brief in support of the PSCSC's order granting the CECPCN was filed on January 12, 2015. Duke Energy Carolinas cannot predict the outcome of this matter.

William States Lee III Nuclear Station

In December 2007, Duke Energy Carolinas applied to the NRC for a COL for two Westinghouse AP1000 (advanced passive) reactors for the proposed William States Lee III Nuclear Station (Lee Nuclear Station) at a site in Cherokee County, South Carolina. Submitting the COL application did not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC concurred with the prudency of Duke Energy Carolinas incurring certain project development and pre-construction costs, although recovery of costs is not guaranteed. Duke Energy Carolinas has incurred approximately $427 million, including AFUDC through December 31, 2014. This amount is included in Net property, plant and equipment on Duke Energy Carolinas’ Consolidated Balance Sheets.

Design changes have been identified in the Westinghouse AP1000 certified design that must be addressed before NRC can complete its review of the Lee Nuclear Station COL application. These design changes set the schedule for completion of the NRC COL application review and issuance of the Lee COL. Receipt of the Lee Nuclear Station COL is currently expected by mid-2016.

Duke Energy Progress

2012 North Carolina Rate Case

On May 30, 2013, the NCUC approved a settlement agreement related to Duke Energy Progress’ request for a rate increase. The Public Staff was a party to the settlement agreement. The settling parties agreed to a two-year step-in rate increase, with the first year providing for a $147 million, or a 4.5 percent average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or a 1.0 percent average increase in rates. The agreement is based upon a return on equity of 10.2 percent and an equity component of the capital structure of 53 percent. The settlement agreement (i) allows for the recognition of nuclear outage expenses over the refueling cycle rather than when the outage occurs, (ii) a $20 million shareholder contribution to agencies that provide energy assistance to low-income customers, and (iii) a reduction in the regulatory liability for costs of removal of $20 million for the first year. The initial rate increase went into effect on June 1, 2013 and the step-in rate increase went into effect in June 2013.

On July 1, 2013, the NCAG appealed the NCUC’s approval of the rate of return and capital structure included in the agreement. NC WARN also appealed various matters in the settlement. On August 20, 2014, the NCSC affirmed the NCUC's order approving Duke Energy Progress' rate of return and capital structure concluding the appeal.

L.V. Sutton Combined Cycle Facility

Duke Energy Progress completed construction of a 625 MW combined cycle natural gas-fired generating facility at its existing L.V. Sutton Steam Station (Sutton) in New Hanover County, North Carolina. Sutton began commercial operations in the fourth quarter of 2013.

Shearon Harris Nuclear Station Expansion

In 2006, Duke Energy Progress selected a site at Harris to evaluate for possible future nuclear expansion. On February 19, 2008, Duke Energy Progress filed its COL application with the NRC for two Westinghouse AP1000 reactors at Harris, which the NRC docketed for review. On May 2, 2013, Duke Energy Progress filed a letter with the NRC requesting the NRC to suspend its review activities associated with the COL at the Harris site. As a result of the decision to suspend the COL applications, during the second quarter of 2013, Duke Energy Progress recorded a pretax impairment charge of $22 million which represented costs associated with the COL, which were not probable of recovery. As of December 31, 2014, approximately $48 million is recorded in Regulatory assets on Duke Energy Progress’ Consolidated Balance Sheets.

Wholesale Depreciation Rates

On April 19, 2013, Duke Energy Progress filed an application with FERC for acceptance of changes to generation depreciation rates and in August 2013 filed for acceptance of additional changes. These changes affect the rates of Duke Energy Progress' wholesale power customers that purchase or will purchase power under formula rates. Certain Duke Energy Progress wholesale customers filed interventions and protests. FERC accepted the depreciation rate changes, subject to refund, and set the matter for settlement and hearing in a consolidated proceeding. FERC further initiated an action with respect to the justness and reasonableness of the proposed rate changes. Settlement was reached in October 2014 for changes to the depreciation rates and conforming changes to the wholesale formula rates. FERC approved the settlement in December 2014. The agreement will have no material or adverse impact to the rates originally proposed by Duke Energy Progress, and Duke Energy Progress will receive cost recovery for early retired plants previously included in the depreciation rates.

Duke Energy Florida

FERC Transmission Return on Equity Complaint

On February 12, 2012, Seminole Electric Cooperative, Inc. and Florida Municipal Power Agency filed with FERC a complaint against Duke Energy Florida alleging that the current rate of return on equity in Duke Energy Florida's transmission formula rates of 10.8 percent is unjust and unreasonable and should be reduced to 9.02 percent. The complainants further alleged that return on equity adjustments should take effect retroactive to January 1, 2010 under the governing transmission formula rate protocols. On May 13, 2013, the complainants filed a second complaint alleging that the return on equity should be reduced to 8.63 percent or 8.84 percent. On June 19, 2014, FERC issued orders consolidating the two complaints, setting them for settlement and hearing procedures, setting refund effective dates of February 29, 2012 for the first complaint and May 13, 2013 for the second complaint, and setting for settlement and hearing the issue of whether return on equity adjustments should take effect prior to the refund effective date of the first complaint. On August 12, 2014, the complainants filed a third complaint alleging that the return on equity should be 8.69 percent. On December 5, 2014, FERC issued an order consolidating the third complaint with the first two complaints for the purposes of settlement, hearing, and decision, and establishing a refund effective date of August 12, 2014 for the third complaint. The parties are engaged in settlement discussions. Duke Energy Florida cannot predict the outcome of this matter.

FPSC Settlement Agreements

On February 22, 2012, the FPSC approved a settlement agreement (the 2012 Settlement) among Duke Energy Florida, the Florida Office of Public Counsel (OPC) and other customer advocates. The 2012 Settlement was to continue through the last billing cycle of December 2016. On October 17, 2013, the FPSC approved a settlement agreement (the 2013 Settlement) between Duke Energy Florida, OPC, and other customer advocates. The 2013 Settlement replaces and supplants the 2012 Settlement and substantially resolves issues related to (i) Crystal River Unit 3, (ii) Levy, (iii) Crystal River 1 and 2 coal units, and (iv) future generation needs in Florida. Refer to the remaining sections below for further discussion of these settlement agreements.

Crystal River Unit 3

On February 5, 2013, Duke Energy Florida announced the retirement of Crystal River Unit 3. On February 20, 2013, Duke Energy Florida filed with the NRC a certification of permanent cessation of power operations and permanent removal of fuel from the reactor vessel. In December 2013, and March 2014, Duke Energy Florida filed an updated site-specific decommissioning plan with the NRC and FPSC, respectively. The plan, which was approved by the FPSC in November 2014, included a decommissioning cost estimate of $1,180 million, including amounts applicable to joint owners, under the SAFSTOR option. Duke Energy Florida’s decommissioning study assumes Crystal River Unit 3 will be in SAFSTOR configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities to be completed by 2073. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three accepted approaches to decommissioning approved by the NRC.

Duke Energy Florida has reclassified all Crystal River Unit 3 investments, including property, plant and equipment, nuclear fuel, inventory, and other assets, to a regulatory asset. Duke Energy agreed to forgo recovery of $295 million of regulatory assets and an impairment charge was recorded in the second quarter of 2013 for this matter. Duke Energy Florida is allowed to accelerate cash recovery of approximately $130 million of the Crystal River Unit 3 regulatory asset from retail customers from 2014 through 2016 through its fuel clause. Duke Energy Florida will begin recovery of the remaining Crystal River Unit 3 regulatory asset, up to a cap of $1,466 million from retail customers upon the earlier of (i) full recovery of the uncollected Levy investment or (ii) the first billing period of January 2017. Recovery will continue 240 months from inception of collection of the regulatory asset in base rates. The Crystal River Unit 3 base rate component will be adjusted at least every four years.

Included in this recovery, but not subject to the cap, are costs of building an independent spent fuel storage installation (ISFSI). The return rate will be based on the currently approved AFUDC rate with a return on equity of 7.35 percent, or 70 percent of the currently approved 10.5 percent. The return rate is subject to change if the return on equity changes in the future. In December 2014, the FPSC approved Duke Energy Florida's decision to construct the ISFSI and approved Duke Energy Florida's request to defer amortization of the ISFSI pending resolution of its litigation against the federal government as a result of the Department of Energy's breach of its obligation to accept spent nuclear fuel. The regulatory asset associated with the original power uprate project to increase generating capacity will continue to be recovered through the Nuclear Cost Recovery Clause over an estimated seven-year period that began in 2013.

Through December 31, 2014, Duke Energy Florida deferred $1,377 million for rate recovery related to Crystal River Unit 3, which is subject to the rate recovery cap in the 2013 Settlement. In addition, Duke Energy Florida deferred $260 million for recovery associated with building an ISFSI and the original uprate project, which is not subject to the rate recovery cap discussed above. Duke Energy Florida does not expect the Crystal River Unit 3 costs to exceed the cap.

Customer Rate Matters

Pursuant to the 2013 Settlement, Duke Energy Florida will maintain base rates at the current level through the last billing period of 2018, subject to the return on equity range of 9.5 percent to 11.5 percent, with exceptions for base rate increases for the recovery of the Crystal River Unit 3 regulatory asset beginning no later than 2017 and base rate increases for new generation through 2018, per the provisions of the 2013 Settlement. Duke Energy Florida is not required to file a depreciation study, fossil dismantlement study or nuclear decommissioning study until the earlier of the next rate case filing or March 31, 2019. The 2012 Settlement provided for a $150 million increase in base revenue effective with the first billing cycle of January 2013. Costs associated with Crystal River Unit 3 investments were removed from retail rate base effective with the first billing cycle of January 2013. Duke Energy Florida is accruing, for future rate-setting purposes, a carrying charge on the Crystal River Unit 3 investment until the Crystal River Unit 3 regulatory asset is recovered in base rates. If Duke Energy Florida’s retail base rate earnings fall below the return on equity range, as reported on a FPSC-adjusted or pro forma basis on a monthly earnings surveillance report, it may petition the FPSC to amend its base rates during the term of the 2013 Settlement.

Duke Energy Florida agreed to refund $388 million to retail customers through its fuel clause, as required by the 2012 Settlement. At December 31, 2014, $120 million remains to be refunded, of which $50 million credit is recorded in Regulatory assets within Current Assets as an offset to deferred fuel and $70 million is recorded in Regulatory liabilities in Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

Levy

On July 28, 2008, Duke Energy Florida applied to the NRC for a COL for two Westinghouse AP1000 reactors at Levy. In 2008, the FPSC granted Duke Energy Florida’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule, together with the associated facilities, including transmission lines and substation facilities. Design changes have been identified in the Westinghouse AP1000 certified design that must be addressed before the NRC can complete its review of the Levy COL application. These design changes set the schedule for completion of the NRC COL application review and issuance of the Levy COL. Based on the current review schedule, the Levy COL is currently expected by mid-2016.

On January 28, 2014, Duke Energy Florida terminated the Levy engineering, procurement and construction agreement (EPC). Duke Energy Florida may be required to pay for work performed under the EPC and to bring existing work to an orderly conclusion, including but not limited to costs to demobilize and cancel certain equipment and material orders placed. As of December 31, 2014, Duke Energy Florida has recorded an exit obligation of $25 million for the termination of the EPC. This liability was recorded within Other in Deferred Credits and Other Liabilities with an offset primarily to Regulatory assets on the Consolidated Balance Sheets. Duke Energy Florida is allowed to recover reasonable and prudent EPC cancellation costs from its retail customers.

The 2012 Settlement provided that Duke Energy Florida include the allocated wholesale cost of Levy as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. In accordance with the 2013 Settlement, Duke Energy Florida ceased amortization of the wholesale allocation of Levy investments against retail rates. In the second quarter of 2013, Duke Energy Florida recorded a pretax charge of $65 million to write off the wholesale portion of Levy investments. This amount is included in Impairment charges on Duke Energy Florida's Statements of Operations and Comprehensive Income.

On October 27, 2014, the FPSC approved Duke Energy Florida rates for 2015 for Levy as filed and consistent with those established in the 2013 Revised and Restated Settlement Agreement. Recovery of the remaining retail portion of the project costs may occur over five years from 2013 through 2017. Duke Energy Florida has an ongoing responsibility to demonstrate prudency related to the wind down of the Levy investment and the potential for salvage of Levy assets. As of December 31, 2014, Duke Energy Florida has a net uncollected investment in Levy of approximately $180 million, including AFUDC. Of this amount, $91 million related to land and the COL is included in Net, property, plant and equipment and will be recovered through base rates and $89 million is included in Regulatory assets within Current Assets on the Consolidated Balance Sheets and will be recovered through the NCRC.

Crystal River 1 and 2 Coal Units

Duke Energy Florida has evaluated Crystal River 1 and 2 coal units for retirement in order to comply with certain environmental regulations. Based on this evaluation, those units will likely be retired by 2018. Once those units are retired Duke Energy Florida will continue recovery of existing annual depreciation expense through the end of 2020. Beginning in 2021, Duke Energy Florida will be allowed to recover any remaining net book value of the assets from retail customers through the Capacity Cost Recovery Clause. In April 2014, the FPSC approved Duke Energy Florida's petition to allow for the recovery of prudently incurred costs to comply with the Mercury and Air Toxics Standard through the Environmental Cost Recovery Clause.

New Generation

The 2013 Settlement establishes a recovery mechanism for additional generation needs. This recovery mechanism, the Generation Base Rate Adjustment, allows recovery of prudent costs of these items through an increase in base rates, upon the in-service date of such assets, without a general rate case at a 10.5 percent return on equity.

On May 27, 2014, Duke Energy Florida petitioned the FPSC for a Determination of Need to (i) construct a 1,640 MW combined cycle natural gas plant in Citrus County, Florida to be in service in 2018 with an estimated cost of $1.5 billion, (ii) construct a 320 MW combustion turbine plant at its existing Suwannee generating facility (Suwannee project) with an estimated cost of $197 million, and (iii) add inlet chilling to its existing Hines Energy Complex (Hines) combined cycle units which will increase the output of those units by 220 MW at an estimated cost of $160 million. These cost estimates include AFUDC. On August 26, 2014, Duke Energy Florida requested the FPSC withdraw consideration for the Suwannee project so that Duke Energy Florida could pursue further negotiations on an alternative power plant acquisition. On October 2, 2014, the FPSC approved the requests for the Citrus County plant and the uprate project at the Hines facility. Additional environmental and governmental approvals will be sought for the Citrus County project. The Hines uprate project is expected to be completed no later than 2017.

In December 2014, Duke Energy Florida and Osprey Energy Center, LLC, a wholly owned subsidiary of Calpine Corporation (Calpine) entered into an Asset Purchase and Sale Agreement for the purchase of a 599 MW combined cycle natural gas plant in Auburndale, Florida (Osprey Plant acquisition) for approximately $166 million. Closing is subject to the approval of FERC, FPSC and the expiration of the Hart Scott Rodino waiting period and is expected to occur by the first quarter of 2017 upon the expiration of an existing Power Purchase Agreement between Calpine and Duke Energy Florida. On January 30, 2015, Duke Energy Florida filed a petition with the FPSC requesting a determination that the Osprey Plant acquisition or, alternatively, the Suwannee project is the most cost effective generation alternative to meet Duke Energy Florida's remaining need prior to 2018.

Cost of Removal Reserve

The 2012 Settlement and the 2013 Settlement provide Duke Energy Florida the discretion to reduce cost of removal amortization expense for a certain portion of the cost of removal reserve until the earlier of its applicable cost of removal reserve reaches zero or the expiration of the 2013 Settlement. Duke Energy Florida may not reduce amortization expense if the reduction would cause it to exceed the appropriate high point of the return on equity range. Duke Energy Florida recognized a reduction in amortization expense of $114 million, and $178 million for the years ended December 31, 2013, and 2012 respectively. Duke Energy Florida had no cost of removal reserves eligible for amortization to income remaining at December 31, 2013.

Duke Energy Ohio

W.C. Beckjord Fuel Release

On August 18, 2014, approximately 9,000 gallons of fuel oil were inadvertently discharged into the Ohio River during a fuel oil transfer at the W.C. Beckjord generating plant. The Ohio Environmental Protection Agency (Ohio EPA) issued a Notice of Violation related to the discharge. Duke Energy Ohio is cooperating with the Ohio EPA, the EPA and the U.S. Attorney for the Southern District of Ohio, responding to a Request for Information from the EPA. No Notice of Violation has been issued by the EPA and no civil or criminal penalty amount has been established. Total repair and remediation costs related to the release are not expected to be material. Other costs related to the release, including state or federal civil enforcement proceedings, cannot be reasonably estimated at this time.

2014 Electric Security Plan (ESP)

On May 29, 2014, Duke Energy Ohio filed an application for approval of an SSO in the form of an ESP, effective June 1, 2015. The proposed ESP includes a competitive procurement process for SSO load, a distribution capital investment rider, a tracking mechanism for incremental distribution costs caused by major storms, and a cost-based recovery of Duke Energy Ohio’s contractual entitlement in OVEC. The proposed plan also seeks rate design modifications and continuance, revision, or termination of existing riders. An evidentiary hearing in this case concluded in November 2014 and final briefs were submitted in December 2014. Duke Energy Ohio cannot predict the outcome of this matter.

Capacity Rider Filing

On August 29, 2012, Duke Energy Ohio applied to the PUCO for the establishment of a charge for capacity provided pursuant to its obligations as a Fixed Resource Requirement entity. The charge, which was consistent with Ohio’s state compensation mechanism, was estimated to be approximately $729 million, and reflected Duke Energy Ohio’s embedded cost of capacity. On February 13, 2014, the PUCO denied Duke Energy Ohio’s request.

2012 Electric Rate Case

On May 1, 2013, the PUCO approved a settlement agreement between Duke Energy Ohio and all intervening parties (the Electric Settlement) related to Duke Energy Ohio’s electric distribution rate case. The Electric Settlement provides for a net increase in electric distribution revenues of $49 million, or an average increase of 2.9 percent, based upon a return on equity of 9.84 percent. Revised rates were effective in May 2013.

2012 Natural Gas Rate Case

On November 13, 2013, the PUCO issued an order approving a settlement among Duke Energy Ohio, the PUCO Staff and intervening parties (the Gas Settlement). The Gas Settlement provided for (i) no increase in base rates for natural gas distribution service and (ii) a return on equity of 9.84 percent. The Gas Settlement provided for a subsequent hearing on Duke Energy Ohio’s request for rider recovery of environmental remediation costs associated with its former MGP sites. After the conclusion of the evidentiary hearing and briefs, the PUCO authorized Duke Energy Ohio to recover $56 million, excluding carrying costs, of environmental remediation costs. The MGP rider became effective in April 2014 for a five-year period. On March 31, 2014, Duke Energy Ohio filed an application with the PUCO to adjust the MGP rider for investigation and remediation costs incurred in 2013. As of December 31, 2014, Duke Energy Ohio has a balance of $115 million in Regulatory assets in the Consolidated Balance Sheets related to MGP sites which includes the $56 million authorized for recovery in the rate case.

On May 14, 2014, the Ohio Supreme Court granted certain consumer groups' motion to stay the MGP rider pending their appeals of the PUCO approval of the Gas Settlement and Duke Energy Ohio suspended billing of the MGP rider in June 2014. Amounts collected under the rider prior to suspension were immaterial. The appellants, the PUCO and Duke Energy Ohio all filed briefs addressing the merits of this matter with the Ohio Supreme Court. On July 29, 2014, the Ohio Supreme Court denied Duke Energy Ohio's motion to lift the stay, but required appellants to post a bond. The Ohio Supreme Court also requested briefs on the appropriate amount of the bond. On November 5, 2014, the Ohio Supreme Court ordered the Appellants to post a bond of approximately $2.5 million to continue the stay of the rider. The bond was to be posted within ten days or the stay would be lifted. The Appellants failed to post the required bond and on November 18, 2014, Duke Energy Ohio requested the PUCO to reinstate the MGP rider. The PUCO approved reinstatement of the rider on January 15, 2015 and Duke Energy Ohio began billings of the MGP rider. Duke Energy Ohio cannot predict the outcome of the appeals in this matter.

Regional Transmission Organization (RTO) Realignment

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

On December 22, 2010, the KPSC approved Duke Energy Kentucky’s request to effect the RTO realignment, subject to a commitment not to seek double-recovery in a future rate case of the transmission expansion fees that may be charged by MISO and PJM in the same period or overlapping periods.

On May 25, 2011, the PUCO approved a settlement between Duke Energy Ohio, Ohio Energy Group, the Office of the Ohio Consumers’ Counsel and the PUCO Staff related to Duke Energy Ohio’s recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MISO Transmission Expansion Planning (MTEP) costs, including but not limited to Multi Value Project (MVP) costs, directly or indirectly charged to Ohio customers. Duke Energy Ohio also agreed to vigorously defend against any charges for MVP projects from MISO.

Upon its exit from MISO on December 31, 2011, Duke Energy Ohio recorded a liability for its exit obligation and share of MTEP costs, excluding MVP. This liability was recorded within Other in Current liabilities and Other in Deferred credits and other liabilities on Duke Energy Ohio’s Consolidated Balance Sheets.

The following table provides a reconciliation of the beginning and ending balance of Duke Energy Ohio’s recorded obligations related to its withdrawal from MISO. As of December 31, 2014, $74 million is recorded as a Regulatory asset on Duke Energy Ohio's Consolidated Balance Sheets.



(in millions)	December 31, 2013		Provision / Adjustments		Cash Reductions			December 31, 2014
Duke Energy Ohio	$	95	$	3	$	(4	)	$	94

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

On December 29, 2011, MISO filed a tariff with the FERC providing for the allocation of MVP costs to a withdrawing owner based on monthly energy usage. The FERC set for hearing (i) whether MISO’s proposed cost allocation methodology to transmission owners who withdrew from MISO prior to January 1, 2012, is consistent with the tariff at the time of their withdrawal from MISO, and, (ii) if not, what the amount of and methodology for calculating any MVP cost responsibility should be. On July 16, 2013, a FERC Administrative Law Judge (ALJ) issued an initial decision. Under this initial decision, Duke Energy Ohio would be liable for MVP costs. Duke Energy Ohio filed exceptions to the initial decision, requesting the FERC overturn the ALJ’s decision. After reviewing the initial decision, along with all exceptions and responses filed by the parties, the FERC will issue a final decision. Duke Energy Ohio fully intends to appeal to the federal court of appeals if the FERC affirms the ALJ’s decision. Duke Energy Ohio cannot predict the outcome of these proceedings.

In 2012, MISO estimated Duke Energy Ohio’s MVP obligation over the period from 2012 to 2071 at $2.7 billion, on an undiscounted basis. The estimated obligation is subject to great uncertainty including the ultimate cost of the projects, the annual costs of operations and maintenance, taxes and return over the project lives, the number of years in service for the projects and the allocation to Duke Energy Ohio.

Any liability related to the MISO MVP matter attributable to the Disposal Group will not be transferred to Dynegy upon closing of the disposal of the Midwest generation business.

FERC Transmission Return on Equity and MTEP Cost Settlement

On October 14, 2011, Duke Energy Ohio and Duke Energy Kentucky submitted with FERC proposed modifications to the PJM Interconnection Open Access Transmission Tariff pertaining to recovery of the transmission revenue requirement as PJM transmission owners. The filing was made in connection with the Duke Energy Ohio's and Duke Energy Kentucky's move from MISO to PJM effective January 1, 2012. On April 24, 2012, FERC issued an order accepting the proposed filing effective January 1, 2012, except that the order denied a request to recover certain costs associated with the move from MISO to PJM without prejudice to the right to submit another filing seeking such recovery and including certain additional evidence, and set the rate of return on equity of 12.38 percent for settlement and hearing. A February 2013 settlement agreement filed with the FERC was rejected in September 2013. On October 30, 2014, the companies and six PJM transmission customers with load in the Duke Energy Ohio and Duke Energy Kentucky zone filed with FERC for approval of another settlement agreement. The principal terms of the settlement agreement are that, effective upon the date of FERC approval, (i) the return on equity will be reduced from 12.38 percent to 11.38 percent and (ii) Duke Energy Ohio and Duke Energy Kentucky will recover 30 percent of costs arising from their obligation to pay any portion of the costs of projects included in any MTEP that was approved prior to the date of the Duke Energy Ohio's and Duke Energy Kentucky's integration into PJM. The settlement is pending FERC approval. Duke Energy Ohio and Duke Energy Kentucky cannot predict the outcome of this matter

Duke Energy Indiana

Edwardsport IGCC Plant

On November 20, 2007, the IURC granted Duke Energy Indiana a Certificate of Public Convenience and Necessity for the construction of a 618 MW IGCC power plant at Duke Energy Indiana’s existing Edwardsport Generating Station in Knox County, Indiana with a cost estimate of $1.985 billion assuming timely recovery of financing costs related to the project. The Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., Save the Valley, Inc., and Valley Watch, Inc. (collectively, the Joint Intervenors) were intervenors in several matters related to the Edwardsport IGCC Plant.

On December 27, 2012, the IURC approved a settlement agreement (the 2012 Edwardsport settlement) related to the cost increase for the construction of the project, including subdockets before the IURC related to the project. The Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel-Indiana were parties to the settlement. The settlement agreement, as approved, capped costs to be reflected in customer rates at $2.595 billion, including estimated AFUDC through June 30, 2012. Duke Energy Indiana is allowed to recover AFUDC after June 30, 2012, until customer rates are revised, with such recovery decreasing to 85 percent on AFUDC accrued after November 30, 2012.

Over the course of construction of the project to date, Duke Energy Indiana has recorded pretax charges of approximately $897 million related to the project and the settlement agreement discussed above. Of this amount, pretax impairment and other charges of $631 million were recorded during the year ended December 31, 2012. These charges were recorded in Impairment charges and Operations, maintenance and other on Duke Energy Indiana's Consolidated Statements of Operations and Comprehensive Income.

The project was placed in commercial operation in June 2013. Costs for the Edwardsport IGCC plant are recovered from retail electric customers through a tracking mechanism, the IGCC rider. Updates to the IGCC rider are filed semi-annually. An order on the eleventh semi-annual IGCC rider is currently pending. The twelfth and thirteenth semi-annual IGGC riders were combined into one proceeding. In this proceeding, the OUCC, Duke Energy Indiana Industrial Group and Joint Intervenors alleged the Edwardsport IGCC plant was not properly placed in commercial operation in June 2013 and therefore operating and maintenance costs for the time period June 2013 through March 2014 should not be recoverable. The Duke Energy Indiana Industrial Group and Joint Intervenors also argued that the plant's performance was unsatisfactory during the first ten months of operations and recommended cost recovery disallowances. Evidentiary hearings concluded in February 2015 and an order is expected in the second half of 2015.

On March 18, 2014, the Indiana Court of Appeals denied an appeal filed by the Joint Intervenors and affirmed the IURC order approving the 2012 Edwardsport settlement and other related regulatory orders. On June 5, 2014, the Indiana Court of Appeals affirmed the decision on rehearing. The Joint Intervenors requested to seek transfer to the Indiana Supreme Court. On November 7, 2014, the Indiana Supreme Court denied the Joint Intervenors' request to transfer the appeal of these proceedings. The ninth and tenth semi-annual IGCC rider orders have also been appealed. On August 21, 2014, the Indiana Court of Appeals affirmed the IURC order in the tenth IGCC rider proceeding, and on October 29, 2014, denied Joint Intervenors' request for rehearing. The Joint Intervenors have requested a transfer of the matter to the Indiana Supreme Court. On September 8, 2014, the Indiana Court of Appeals remanded the IURC order in the ninth IGCC rider proceeding back to the IURC for further findings concerning approximately $61 million of financing charges Joint Intervenors claimed were caused by construction delay and a ratemaking issue concerning the in-service date determination for tax purposes. On February 25, 2015, the IURC issued an order on remand that upheld its prior order and added additional findings on the two issues as requested by the Indiana Court of Appeals. First, the IURC concluded the schedule delays in the construction of the IGCC plant were not the result of imprudence or unreasonable actions by Duke Energy Indiana and therefore recovery of the financing costs were appropriate. On the second issue, the IURC determined the federal tax in-service determination was to be made by the Internal Revenue Service, not the IURC, and the IURC appropriately reviewed and accepted the impact of such decision on customer rates in this and prior proceedings.

On April 2, 2014, the IURC established a subdocket to Duke Energy Indiana’s current fuel adjustment clause proceeding. In this fuel adjustment subdocket, the IURC intends to review underlying causes for net negative generation amounts at the Edwardsport IGCC plant during the period September through November 2013. Duke Energy Indiana contends the net negative generation is related to the consumption of fuel and auxiliary power when the plant was in start-up or off line. In addition to the OUCC, the Duke Energy Indiana Industrial Group, Nucor Steel-Indiana, Steel Dynamics, Inc., and the Joint Intervenors are parties to the subdocket. The IURC has deferred the fuel adjustment subdocket until resolution of the twelfth and thirteenth semi-annual IGCC rider proceedings. In addition, although the IURC approved fuel adjustment clause recovery for the period December 2013 through March 2014, it determined such fuel costs reasonably related to the operational performance of the Edwardsport IGCC plant shall be subject to refund pending the outcome of the twelfth and thirteenth semi-annual IGCC riders.

Duke Energy Indiana cannot predict the outcome of the fuel adjustment clause proceedings or pending and future IGCC Rider proceedings.

FERC Transmission Return on Equity Complaint

On November 12, 2013, customer groups filed with FERC a complaint against MISO and its transmission-owning members, including Duke Energy Indiana, alleging, among other things, that the current base rate of return on equity earned by MISO transmission owners of 12.38 percent is unjust and unreasonable and should be reduced to 9.15 percent. On October 16, 2014, FERC issued an order setting the return on equity issue for settlement and hearing and establishing a refund effective date of November 12, 2013. On November 6, 2014, the MISO transmission owners submitted revisions to the MISO tariff to implement a 0.50 percent adder to the base return on equity based on participation in a RTO. On January 5, 2015, FERC issued an order accepting the adder subject to it being applied to a base return on equity that is shown to be just and reasonable in the pending base return on equity complaint. On January 5, 2015, settlement procedures in the base return on equity proceeding were terminated and a hearing was scheduled for August 17, 2015. On February 12, 2015, certain MISO transmission customers filed with FERC a complaint alleging that the base return on equity should be 8.67 percent and requesting consolidation with the pending base return on equity complaint. Duke Energy Indiana cannot predict the outcome of this matter.

Grid Infrastructure Improvement Plan

On August 29, 2014, Duke Energy Indiana filed a seven-year grid infrastructure improvement plan with the IURC with an estimated cost of $1.9 billion, focusing on the reliability, integrity and modernization of the transmission and distribution system. If approved, 80 percent of the costs will be recovered through a rate rider. The remaining 20 percent are subject to recovery through future rate case proceedings. Hearings were held in January 2015 and Duke Energy Indiana expects a decision in the second quarter of 2015.

Other Regulatory Matters

Atlantic Coast Pipeline

On September 2, 2014, Duke Energy, Dominion Resources (Dominion), Piedmont Natural Gas and AGL Resources announced the formation of a joint venture, Atlantic Coast Pipeline, LLC, to build and own the proposed Atlantic Coast Pipeline (ACP), a 550-mile interstate natural gas pipeline. The ACP is designed to meet the needs identified in requests for proposals by Duke Energy Carolinas, Duke Energy Progress and Piedmont Natural Gas. Dominion will build and operate the ACP and will own 45 percent. Duke Energy will own 40 percent of the pipeline through its Commercial Power segment. The remaining share will be owned by Piedmont Natural Gas and AGL Resources. Duke Energy Carolinas and Duke Energy Progress will be customers of the pipeline and enter into 20-year transportation capacity contracts with ACP, subject to state regulatory approval. In October 2014, the NCUC and PSCSC approved the Duke Energy Carolinas and Duke Energy Progress requests to enter into certain affiliate agreements, pay compensation to ACP and to grant a waiver of certain Code of Conduct provisions relating to contractual and jurisdictional matters. The project will require FERC approval, which the joint venture will seek to secure by summer 2016. The estimated in-service date of the pipeline is late 2018.

East Bend Station

On December 30, 2014, Duke Energy Ohio acquired The Dayton Power and Light Company’s 31 percent interest in East Bend Station for approximately $12.4 million. The purchase price has been reflected in the accompanying financial statements with the net purchase amount as an increase to property, plant and equipment in accordance with FERC guidelines. Duke Energy Ohio expects FERC approval to present the property, plant and equipment and accumulated depreciation at The Dayton Power and Light Company's historical cost.

NC WARN FERC Complaint

On December 16, 2014, NC WARN filed a complaint with the FERC against Duke Energy Carolinas and Duke Energy Progress that alleged Duke Energy Carolinas and Duke Energy Progress manipulated the electricity market by constructing costly and unneeded generation facilities leading to unjust and unreasonable rates; Duke Energy Carolinas and Duke Energy Progress failed to comply with Order 1000 by not effectively connecting their transmission systems with neighboring utilities which also have excess capacity; the plans of Duke Energy Carolinas and Duke Energy Progress for unrealistic future growth leads to unnecessary and expensive generating plants; FERC should investigate the practices of Duke Energy Carolinas and Duke Energy Progress and the potential benefits of having them enter into a regional transmission organization; and FERC should force Duke Energy Carolinas and Duke Energy Progress to purchase power from other utilities rather than construct wasteful and redundant power plants. A copy of the complaint was filed with the PSCSC on January 6, 2015. Duke Energy Carolinas and Duke Energy Progress have filed a responses requesting dismissal of the complaint with the FERC and the PSCSC. Duke Energy Carolinas and Duke Energy Progress cannot predict the outcome of these proceedings.

Merger Appeals

On January 9, 2013, the City of Orangeburg and NC WARN appealed the NCUC’s approval of the merger between Duke Energy and Progress Energy. On April 29, 2013, the NCUC granted Duke Energy’s motion to dismiss certain exceptions contained in NC WARN’s appeal.

On March 4, 2014, the Court of Appeals issued an opinion affirming the NCUC’s approval of the merger. On April 8, 2014, NC WARN filed a petition for discretionary review by the North Carolina Supreme Court. On April 21, 2014, Duke Energy and the Public Staff jointly filed their response opposing NC WARN’s petition. The City of Orangeburg did not file a petition for discretionary review. On December 19, 2014, the North Carolina Supreme Court denied NC WARN's petition, concluding the appeal.

Progress Energy Merger FERC Mitigation

In June 2012, the FERC approved the merger with Progress Energy, including Duke Energy and Progress Energy’s revised market power mitigation plan, the Joint Dispatch Agreement (JDA) and the joint Open Access Transmission Tariff. Several intervenors filed requests for rehearing challenging various aspects of the FERC approval. On October 29, 2014, FERC denied all of the requests for rehearing.

The revised market power mitigation plan provided for the acceleration of one transmission project and the completion of seven other transmission projects (Long-Term FERC Mitigation) and interim firm power sale agreements during the completion of the transmission projects (Interim FERC Mitigation). The Long-Term FERC Mitigation was expected to increase power imported into the Duke Energy Carolinas and Duke Energy Progress service areas and enhance competitive power supply options in the service areas. All of these projects were completed in or before 2014. On May 30, 2014, the Independent Monitor filed with FERC a final report stating that the Long-Term FERC Mitigation is complete. Therefore, Duke Energy Carolinas' and Duke Energy Progress' obligations associated with the Interim FERC Mitigation have terminated. In the second quarter of 2014, Duke Energy Progress recorded an $18 million partial reversal of an impairment recorded in the third quarter of 2012. This reversal adjusts the initial disallowance from the Long-Term FERC mitigation and reflects updated information on the construction costs and in-service dates of the transmission projects.

Following the closing of the merger, outside counsel reviewed Duke Energy’s mitigation plan and discovered a technical error in the calculations. On December 6, 2013, Duke Energy submitted a filing to the FERC disclosing the error and arguing that no additional mitigation is necessary. The City of New Bern filed a protest and requested that FERC order additional mitigation. On October 29, 2014, FERC ordered that the amount of the stub mitigation be increased from 25 MW to 129 MW. The stub mitigation is Duke Energy’s commitment to set aside for third parties a certain quantity of firm transmission capacity from Duke Energy Carolinas to Duke Energy Progress during summer off-peak hours. FERC also ordered that Duke Energy operate certain phase shifters to create additional import capability and that such operation be monitored by an independent monitor. Duke Energy does not expect the costs to comply with this order to be material. FERC also referred Duke Energy’s failure to expressly designate the phase shifter reactivation as a mitigation project in Duke Energy’s original mitigation plan filing in March 2012 to the FERC Office of Enforcement for further inquiry. Duke Energy cannot predict the outcome of this additional inquiry.

Planned and Potential Coal Plant Retirements

The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (10 to 20 years) and options being considered to meet those needs. Recent IRPs filed by the Subsidiary Registrants included planning assumptions to potentially retire certain coal-fired generating facilities in Florida, Ohio and Indiana earlier than their current estimated useful lives. These facilities do not have the requisite emission control equipment, primarily to meet EPA regulations recently approved or proposed.

The table below contains the net carrying value of generating facilities planned for early retirement or being evaluated for potential retirement included in Net property, plant and equipment on the Consolidated Balance Sheets, excluding the Duke Energy Carolinas 170 MW Lee Unit 3 which is being converted to gas in 2015.



	December 31, 2014
	Duke Energy		Progress Energy_(b)		Duke Energy Florida_(b)		Duke Energy Ohio_(c)		Duke EnergyIndiana_(d)
Capacity (in MW)	1,704		873		873		163		668
Remaining net book value (in millions)^(a)	$	239	$	114	$	114	$	9	$	116


(a)	Included in Net property, plant and equipment as of December 31, 2014, on the Consolidated Balance Sheets.


(b)	Includes Crystal River Units 1 and 2.


(c)	Includes Miami Fort Unit 6 which is expected to be retired by June 1, 2015.


(d)	Includes Wabash River Units 2 through 6. Wabash River Unit 6 is being evaluated for potential conversion to gas. Duke Energy Indiana committed to retire or convert these units by June 2018 in conjunction with a settlement agreement associated with the Edwardsport air permit.

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