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, 2015
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana
Regulatory Assets
Asset retirement obligations – coal ash	$	2,555	$	1,120	$	1,394	$	1,386	$	8	$	4	$	37
Asset retirement obligations – nuclear and other	838		104		487		195		292		—		—
Accrued pension and OPEB	2,151		479		807		366		441		139		220
Retired generation facilities	509		49		409		179		230		—		51
Debt fair value adjustment	1,191		—		—		—		—		—		—
Net regulatory asset related to income taxes	1,075		564		318		106		212		55		120
Nuclear asset securitizable balance, net	1,237		—		1,237		—		1,237		—		—
Hedge costs and other deferrals	571		127		410		171		239		7		27
Demand side management (DSM)/Energy efficiency (EE)	340		80		250		237		13		10		—
Grid Modernization	68		—		—		—		—		68		—
Vacation accrual	192		79		38		38		—		5		10
Deferred fuel and purchased power	151		21		129		93		36		1		—
Nuclear deferral	245		107		138		62		76		—		—
Post-in-service carrying costs and deferred operating expenses	383		97		38		38		—		21		227
Gasification services agreement buyout	32		—		—		—		—		—		32
Transmission expansion obligation	72		—		—		—		—		72		—
Manufactured gas plant (MGP)	104		—		—		—		—		104		—
NCEMPA deferrals	21		—		21		21		—		—		—
East Bend deferrals	16		—		—		—		—		16		—
Other	499		244		121		82		39		31		94
Total regulatory assets	12,250		3,071		5,797		2,974		2,823		533		818
Less: current portion	877		305		362		264		98		36		102
Total noncurrent regulatory assets	$	11,373	$	2,766	$	5,435	$	2,710	$	2,725	$	497	$	716



	December 31, 2015
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana
Regulatory Liabilities
Costs of removal	$	5,329	$	2,413	$	2,078	$	1,725	$	353	$	222	$	616
Amounts to be refunded to customers	71		—		—		—		—		—		71
Storm reserve	150		24		125		—		125		1		—
Accrued pension and OPEB	288		68		51		25		26		21		83
Deferred fuel and purchased power	311		55		255		58		197		1		—
Other	506		281		164		155		8		12		46
Total regulatory liabilities	6,655		2,841		2,673		1,963		709		257		816
Less: current portion	400		39		286		85		200		12		62
Total noncurrent regulatory liabilities	$	6,255	$	2,802	$	2,387	$	1,878	$	509	$	245	$	754



	December 31, 2014
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		Indiana
Regulatory Assets
Asset retirement obligations – coal ash	$	1,992	$	840	$	1,152	$	1,152	$	—	$	—	$	—
Asset retirement obligations – nuclear and other	1,025		67		730		432		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
DSM/EE	330		106		203		193		10		21		—
Grid Modernization	76		—		—		—		—		76		—
Vacation accrual	213		86		46		46		—		6		12
Deferred fuel and purchased power	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		—
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 noncurrent regulatory assets	$	11,042	$	2,465	$	5,408	$	2,675	$	2,733	$	512	$	685



	December 31, 2014
			Duke				Duke		Duke		Duke		Duke
	Duke		Energy		Progress		Energy		Energy		Energy		Energy
(in millions)	Energy		Carolinas		Energy		Progress		Florida		Ohio		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 and purchased power	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 noncurrent regulatory liabilities	$	6,193	$	2,710	$	2,379	$	1,832	$	547	$	241	$	796

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 – coal ash. Represents regulatory assets including deferred depreciation and accretion related to the legal obligation to close ash basins. The costs are deferred until recovery treatment has been determined. The recovery period for these costs has yet to be established. Duke Energy Carolinas, Duke Energy Progress and Duke Energy Ohio earn a debt return on their expenditures. See Notes 1 and 9 for additional information.

Asset retirement obligations – nuclear and other. Represents regulatory assets, including deferred depreciation and accretion, related to legal obligations associated with the future retirement of property, plant and equipment, excluding amounts related to coal ash. The Asset retirement obligations relate primarily to decommissioning nuclear power facilities. The amounts also include certain deferred gains on NDTF investments. 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 2086. 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 and unrecognized prior service cost and credit 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 and prior service cost and credit to net periodic benefit costs for pension and OPEB plans. See Note 21 for additional detail.

Retired generation facilities. Duke Energy Florida earns a full return on a portion of the regulatory asset related to the retired nuclear plant currently recovered in the nuclear cost recovery clause (NCRC), with the remaining portion earning a reduced return. Duke Energy Carolinas earns a return on the outstanding retail balance with recovery periods ranging from five 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 recorded to state the carrying value of Progress Energy at fair value in connection with the 2012 merger. 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. Amounts for Duke Energy, Duke Energy Carolinas, Progress Energy and Duke Energy Progress include regulatory liabilities related to the change in the North Carolina corporate tax rate discussed in Note 22.

Nuclear asset securitizable balance, net. Represents the balance associated with Crystal River Unit 3 retirement approved for recovery by the FPSC on September 15, 2015, and the deferred operating expenses expected to be securitized in 2016 upon issuance of the associated bonds. The regulatory asset balance is net of the AFUDC equity portion of the $1.283 billion amount approved by the FPSC. The regulatory asset balance approved for recovery by the FPSC will earn a reduced return until the expected bond issuance, after which it will earn a return in rates to recover the interest costs of the associated debt. Once bonds are issued, the balance will be recovered over approximately 20 years. This regulatory asset is not included in rate base.

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 2048.

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 is over the life of the assets. Duke Energy Ohio is earning a return on these costs.

Vacation accrual. Generally recovered within one year.

Deferred fuel and purchased power. Represents certain energy related costs that are recoverable or refundable as approved by the applicable regulatory body. Duke Energy Florida amount includes capacity costs. Duke Energy Florida earns a return on the retail portion of under-recovered costs. Duke Energy Ohio earns 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 amounts include certain purchased power costs in both North Carolina and South Carolina and costs of distributed energy resource programs in South Carolina. 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, with a final true-up to be filed by May 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 2082.

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 costs incurred through 2019. Duke Energy Ohio does not earn a return on these costs.

NCEMPA deferrals. Represents retail allocated cost deferrals and returns associated with the additional ownership interest in assets acquired from NCEMPA discussed in Note 2. The North Carolina retail allocated costs are generally being recovered, over a period of time between three years and the remaining life of the assets purchased, through a rider that became effective on December 1, 2015. The South Carolina retail allocated costs are being deferred until Duke Energy Progress' next general rate case, earning a return pursuant to an order received from the PSCSC.

East Bend deferrals. Represents both deferred operating expenses and deferred depreciation as well as carrying costs on the portion of East Bend that was acquired from Dayton Power and Light and that had been previously operated as a jointly owned facility. Recovery will not commence until the settlement of the next rate case in Kentucky. Duke Energy Ohio is earning a return on these deferred costs.

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 period of refund for Duke Energy Indiana is through 2017.

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, 2015.

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, 2015.

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

FERC Transmission Return on Equity Complaint

On January 7, 2016, a customer group filed a complaint with the FERC that the rate of return on equity of 10.2 percent in Duke Energy Carolinas' transmission formula rates is excessive and should be reduced to no higher than 8.49 percent, effective upon the complaint date. The customer group requests consolidation with a similar complaint filed against Duke Energy Progress on the same day. Duke Energy Carolinas cannot predict the outcome of this matter.

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 Duke Energy Carolinas' existing William States Lee Generating Station in Anderson, South Carolina. Duke Energy Carolinas began construction in July 2015 and estimates 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, claiming the PSCSC did not properly consider a request related to a proposed solar facility prior to granting approval of the CECPCN. The Court of Appeals affirmed the PSCSC's decision on February 10, 2016. On February 23, 2016, the South Carolina Coastal Conservation League and Southern Alliance for Clean Energy filed a petition for rehearing with the Court of Appeals.

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 $471 million, including AFUDC through December 31, 2015. 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 late 2016.

Duke Energy Progress

FERC Transmission Return on Equity Complaint

On January 7, 2016, a customer group filed a complaint with the FERC that the rate of return on equity of 10.8 percent in Duke Energy Progress' transmission formula rates is excessive and should be reduced to no higher than 8.49 percent, effective upon the complaint date. The customer group requests consolidation with a similar complaint filed against Duke Energy Carolinas on the same day. Duke Energy Progress cannot predict the outcome of this matter.

Sutton Black Start Combustion Turbine CPCN

On April 15, 2015, Duke Energy Progress filed a Certificate of Public Convenience and Necessity (CPCN) application with the NCUC for approval to construct an 84 MW black start combustion turbine (CT) project at the existing Sutton Plant (Sutton Black Start CT Project). The Sutton Black Start CT Project would replace three existing CTs with total capacity of 61 MW with two new 42 MW CT units with black start and fast start capability. In addition to peaking system capacity, the Sutton Black Start CT Project will provide regional black start capability and tertiary backup power services for the Brunswick Nuclear Plant. In June 2015, the Public Staff of the NCUC recommended the NCUC approve Duke Energy Progress' application. On August 3, 2015, the NCUC issued an order granting the application and requiring annual construction and cost progress reports. The new units are expected to be commercially available in the summer of 2017.

Western Carolinas Modernization Plan

In May 2015, Duke Energy Progress announced a $1.1 billion plan to modernize the Western Carolinas energy system. The plan included retirement of the Asheville coal-fired plant, building a 650 MW combined-cycle natural gas power plant, installing solar generation at the site, building new transmission lines, a new substation and upgrades to area substations. On June 24, 2015, the North Carolina governor signed into law the North Carolina Mountain Energy Act of 2015 (Mountain Energy Act) which provides for an expedited CPCN process for the proposed Asheville combined-cycle project and extends certain North Carolina Coal Ash Management Act of 2014 (Coal Ash Act) deadlines for the coal ash basin at the Asheville Plant site.

On November 4, 2015, in response to community feedback, Duke Energy Progress announced a revised plan. The revised plan replaces the planned 650 MW plant with two 280 MW combined-cycle natural gas plants having dual fuel capability, with the option to build a third natural gas simple cycle unit in 2023 based upon the outcome of initiatives to reduce the region's power demand. The revised plan includes upgrades to existing transmission lines and substations, but eliminates the need for a new transmission line and a new substation associated with the project in South Carolina. The revised plan has the same overall project cost as the original plan, and the plans to install solar generation remain unchanged. Duke Energy Progress has also proposed to add a pilot battery storage project. These investments will be made within the next seven years. Duke Energy Progress is also working with the local natural gas distribution company to upgrade an existing natural gas pipeline to serve the natural gas plant. The plan requires various approvals including regulatory approvals in North Carolina. Duke Energy Progress filed for a CPCN with the NCUC for the new gas units on January 15, 2016. At the NCUC's staff conference on February 22, 2016, the Public Staff recommended approval of the CPCN for the two combined cycle natural gas plants and recommended that the NCUC not issue a CPCN for the simple cycle unit at this time. The NCUC also heard arguments from intervenors and Duke Energy Progress. Pursuant to the Mountain Energy Act, the NCUC's deadline to issue a decision on the CPCN is February 29, 2016.

The carrying value of the 376 MW Asheville coal-fired plant, including associated ash basin closure costs, of $548 million is included in Generation facilities to be retired, net on Duke Energy Progress' Consolidated Balance Sheet as of December 31, 2015.

Shearon Harris Nuclear Plant 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. The NCUC and PSCSC have approved deferral for $48 million of retail costs recorded in Regulatory assets on Duke Energy Progress’ Consolidated Balance Sheets.

Duke Energy Florida

FERC Transmission Return on Equity Complaint

Seminole Electric Cooperative, Inc. and Florida Municipal Power Agency filed multiple complaints with the FERC alleging Duke Energy Florida's current rate of return on equity in transmission formula rates of 10.8 percent is unjust and unreasonable. The latest complaint, filed on August 12, 2014, claims the rate of return on equity should be reduced to 8.69 percent. The FERC consolidated all complaints for the purposes of settlement, hearing and decision. On July 21, 2015, the parties filed with the FERC for approval of a settlement agreement under which (i) Duke Energy Florida will pay a total of $14.1 million as refunds for all periods through December 31, 2014, (ii) the rate of return on equity will be 10 percent effective January 1, 2015, and (iii) none of the parties will seek a change in the rate of return on equity prior to January 1, 2018. On November 19, 2015, the FERC approved the settlement agreement resolving all complaints. Duke Energy Florida paid $14.1 million in refunds during December 2015.

Citrus County Combined Cycle Facility

On October 2, 2014, the FPSC granted Duke Energy Florida a Determination of Need for the construction of a 1,640 MW combined-cycle natural gas plant in Citrus County, Florida. On May 5, 2015, the Florida Department of Environmental Protection approved Duke Energy Florida's Site Certification Application. The facility is expected to be commercially available in 2018 at an estimated cost of $1.5 billion, including AFUDC. The project has received all required permits and approvals and construction began in October 2015.

Purchase of Osprey Energy Center

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. On January 30, 2015, Duke Energy Florida petitioned the FPSC requesting a determination that the Osprey Plant acquisition or, alternatively, the construction of a 320 MW combustion turbine at its existing Suwannee generating facility (Suwannee project) with an estimated cost of $197 million, is the most cost-effective generation alternative to meet Duke Energy Florida's remaining generation need prior to 2018. On July 21, 2015, the FPSC approved the Osprey Plant acquisition as the most cost-effective alternative and issued an order of approval on July 31, 2015. On July 24, 2015, the FERC issued an order approving the Osprey Plant acquisition. Closing of the acquisition is contingent upon 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.

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 at that time, 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 2074. 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.

Pursuant to the 2013 Settlement, Duke Energy Florida reclassified all Crystal River Unit 3 investments, including property, plant and equipment, nuclear fuel, inventory, and other assets, to regulatory assets. Portions of the nuclear fuel balances that are under contract for sale were subsequently moved to Other within Current Assets and Other within Investments and Other Assets on the Consolidated Balance Sheets. Duke Energy Florida 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 also accelerated cash recovery of approximately $47 million, net of tax, of the Crystal River Unit 3 regulatory asset from retail customers during 2014 and 2015, through its fuel clause.

On May 22, 2015, Duke Energy Florida petitioned the FPSC for approval to include in base rates the revenue requirement for the projected $1.298 billion Crystal River Unit 3 regulatory asset as authorized by the 2013 Revised and Restated Stipulation and Settlement Agreement (2013 Agreement). On September 15, 2015, the FPSC approved Duke Energy Florida's motion for approval of a settlement agreement with intervenors to reduce the value of the projected Crystal River Unit 3 regulatory asset to be recovered to $1.283 billion as of December 31, 2015. An impairment charge of $15 million was recognized in the third quarter of 2015 to adjust the regulatory asset balance.

In June 2015, the governor of Florida signed legislation to allow utilities to securitize certain retired nuclear generation assets, with approval of the FPSC. On November 19, 2015, the FPSC issued a financing order approving Duke Energy Florida’s request to securitize its unrecovered regulatory asset related to Crystal River Unit 3 through a debt issuance at a wholly owned special purpose entity. Securitization would replace the base rate recovery methodology authorized by the 2013 Agreement and result in a lower rate impact to customers with an approximately 20 year recovery period. On February 9, 2016, Duke Energy Florida filed a registration statement for the proposed initial public offering of the bonds. Use of the registration statement for purposes of the offering is subject to review and declaration of its effectiveness by the SEC. Duke Energy Florida expects to issue securitization bonds in the first half of 2016.

In December 2014, the FPSC approved Duke Energy Florida's decision to construct an independent spent fuel storage installation (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 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. Through December 31, 2015 Duke Energy Florida has deferred approximately $60 million for recovery associated with building the ISFSI.

The regulatory asset associated with the original Crystal River Unit 3 power uprate project will continue to be recovered through the NCRC over an estimated seven-year period that began in 2013 with a remaining uncollected balance at December 31, 2015 of $169 million.

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, unless the regulatory asset is securitized as discussed above, 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 also provided for a $150 million increase in base revenue effective with the first billing cycle of January 2013. 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, 2015, $70 million remains to be refunded and is included in Regulatory liabilities within Current Liabilities on the Consolidated Balance Sheets.

Levy Nuclear Project

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 late 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. Duke Energy Florida recorded an exit obligation of $25 million in first quarter 2014 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, 2015, Duke Energy Florida has a net uncollected investment in Levy of approximately $183 million, including AFUDC. Of this amount, $105 million related to land and the COL is included in Net, property, plant and equipment and will be recovered through base rates and $78 million is included in Regulatory assets within Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets and will be recovered through the NCRC.

On April 16, 2015, the FPSC approved Duke Energy Florida’s petition to cease collection of the Levy Nuclear Project fixed charge beginning with the first billing cycle in May 2015. On August 18, 2015, the FPSC approved leaving the Levy Nuclear Project portion of the Nuclear Cost Recovery Clause charge at zero dollars for 2016 and 2017, consistent with the 2013 Settlement. Duke Energy Florida will submit by May 2017 a true-up of Levy Nuclear Project costs or credits to be recovered no earlier than January 2018. To the extent costs become known after May 2017, Duke Energy Florida will petition for recovery at that time.

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.

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 could 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 for the year ended December 31, 2013. Duke Energy Florida had no cost of removal reserves eligible for amortization to income remaining after December 31, 2013.

Duke Energy Ohio

Accelerated Natural Gas Service Line Replacement Rider

On January 20, 2015, Duke Energy Ohio filed an application for approval of an accelerated natural gas service line replacement program (ASRP). The ASRP is modeled after the accelerated main replacement program (AMRP), which concluded on December 31, 2015. Under the ASRP, Duke Energy Ohio proposes to replace certain natural gas service lines on an accelerated basis. The program is proposed to last 10 years. Through the ASRP, Duke Energy Ohio also proposes to complete preliminary survey and investigation work related to natural gas service lines that are customer-owned and for which it does not have valid records and, further, to relocate interior natural gas meters to suitable exterior locations where such relocation can be accomplished. Duke Energy Ohio projects total capital and operations and maintenance expenditures under the ASRP to approximate $320 million. The filing also seeks approval of Rider ASRP, the rider through which expenditures would be recovered. Similar to the Rider AMRP methodology, Duke Energy Ohio proposes to update Rider ASRP on an annual basis. Duke Energy Ohio’s application is pending before the PUCO and it is uncertain when an order will be issued.

Intervenors oppose the ASRP, primarily because they believe the program is neither required nor necessary under federal pipeline regulation. The hearing concluded on November 19, 2015 and initial and reply briefs were filed, with briefing complete on December 23, 2015.

Duke Energy Ohio cannot predict the outcome of this matter.

Energy Efficiency Cost Recovery

On March 28, 2014, Duke Energy Ohio filed an application for recovery of program costs, lost distribution revenue and performance incentives related to its energy efficiency and peak demand reduction programs. These programs are undertaken to comply with environmental mandates set forth in Ohio law. After a comment period, the PUCO approved Duke Energy Ohio’s application, but found that Duke Energy Ohio was not permitted to use banked energy savings from previous years in order to calculate the amount of allowed incentive. This conclusion represented a change to the cost recovery mechanism that had been agreed to by intervenors and approved by the PUCO in previous cases. As a result of the PUCO’s decision, Duke Energy Ohio reversed $23 million in revenues deemed to be refundable for the period between January 2013 and April 2015 in second quarter 2015. The PUCO granted Duke Energy Ohio's application for rehearing on July 8, 2015. Substantive ruling on the application for rehearing is pending. The PUCO granted all applications for rehearing for future consideration. On January 6, 2016, Duke Energy Ohio and PUCO Staff entered into a stipulation, pending PUCO approval, resolving the issues related to, among other things, performance incentives and the PUCO Staff audit of 2013 costs. Based on this stipulation, in December 2015, Duke Energy Ohio re-established approximately $20 million of the revenues that had been reversed in the second quarter. A hearing on the stipulation is scheduled for March 10, 2016. Duke Energy Ohio cannot predict the outcome of this matter.

East Bend Station

On December 30, 2014, Duke Energy Ohio acquired The Dayton Power and Light Company's (DP&L) 31 percent interest in the jointly owned East Bend Station for approximately $12.4 million. The purchase price, in accordance with FERC guidelines, was reflected with the net purchase amount as an increase to property, plant and equipment as of December 31, 2014 and with the DP&L's historical original cost as an increase to property, plant and equipment and accumulated depreciation as of December 31, 2015. On August 20, 2015, the KPSC approved Duke Energy Kentucky's application to use the purchase price as the value of the newly acquired interest in the East Bend Station for depreciation purposes and ratemaking.

2014 Electric Security Plan (ESP)

In April 2015, the PUCO modified and approved Duke Energy Ohio's proposed ESP, with a three-year term and an effective date of June 1, 2015. The PUCO approved a competitive procurement process for SSO load, a distribution capital investment rider and a tracking mechanism for incremental distribution expenses caused by major storms. The PUCO order also approved a placeholder tariff for a price stabilization rider, but denied Duke Energy Ohio's specific request to include Duke Energy Ohio's entitlement to generation from OVEC in the rider at this time; however, the order allows Duke Energy Ohio to submit additional information to request recovery in the future. On May 4, 2015, Duke Energy Ohio filed an application for rehearing requesting the PUCO to modify or amend certain aspects of the order. On May 28, 2015, the PUCO granted all applications for rehearing filed in the case for future consideration. Duke Energy Ohio cannot predict the outcome of the appeals in this matter.

During May and November 2015, Duke Energy Ohio completed two competitive bidding processes with results approved by the PUCO to procure a portion of the supply for its SSO load for the term of the ESP.

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. 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.

Certain consumer groups appealed the PUCO’s decision authorizing the MGP rider to the Ohio Supreme Court and asked the court to stay implementation of the PUCO’s order and collections under the MGP rider pending their appeal. The Ohio Supreme Court granted the motion to stay and subsequently required the posting of a bond to effectuate the stay. When the bond was not posted, the PUCO approved Duke Energy Ohio’s request, in January 2015, to reinstate collections under the MGP rider and Duke Energy Ohio resumed billings. Amounts collected prior to the suspension of the rider were immaterial. On March 31, 2015, Duke Energy Ohio filed an application to adjust the MGP rider to recover remediation costs incurred in 2014. Duke Energy Ohio cannot predict the outcome of the appeal of this matter.

Regional Transmission Organization (RTO) Realignment

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

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

On May 25, 2011, the PUCO approved a settlement between Duke Energy Ohio, Ohio Energy Group, the Office of Ohio Consumers’ Counsel and the PUCO Staff related to Duke Energy Ohio’s recovery of certain costs of the RTO realignment via a non-bypassable rider. Duke Energy Ohio is allowed to recover all MISO Transmission Expansion 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, 2015, $72 million is recorded as a Regulatory asset on Duke Energy Ohio's Consolidated Balance Sheets.



			Provisions/		Cash
(in millions)	December 31, 2014		Adjustments		Reductions			December 31, 2015
Duke Energy Ohio	$	94	$	3	$	(5	)	$	92

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. 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. 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 FERC to overturn the ALJ’s decision.

On October 29, 2015, the FERC issued an order reversing the ALJ's decision. The FERC ruled the cost allocation methodology is not consistent with the MISO tariff and that Duke Energy Ohio has no liability for MVP costs after its withdrawal from MISO. On November 30, 2015, MISO filed with the FERC a request for rehearing. Duke Energy Ohio cannot predict the outcome of this matter.

FERC Transmission Return on Equity and MTEP Cost Settlement

On October 14, 2011, Duke Energy Ohio and Duke Energy Kentucky submitted with the 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 Duke Energy Ohio's and Duke Energy Kentucky's move from MISO to PJM effective December 31, 2011. On April 24, 2012, the 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. On April 16, 2015, the FERC approved a settlement agreement between Duke Energy Ohio, Duke Energy Kentucky and six PJM transmission customers with load in the Duke Energy Ohio and Duke Energy Kentucky zone. The principal terms of the settlement agreement are that, effective upon the date of FERC approval, (i) the return on equity for wholesale transmission service is reduced to 11.38 percent, (ii) the settling parties agreed not to seek a change in the return on equity that would be effective prior to June 1, 2017, and (iii) Duke Energy Ohio and Duke Energy Kentucky will recover 30 percent of the wholesale portion 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 Duke Energy Ohio's and Duke Energy Kentucky's integration into PJM.

Duke Energy Indiana

Edwardsport Integrated Gasification Combined Cycle (IGCC) Plant

On November 20, 2007, the IURC granted Duke Energy Indiana a CPCN for the construction of the Edwardsport IGCC Plant. 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. The Edwardsport IGCC Plant was placed in commercial operation in June 2013. Costs for the Edwardsport IGCC Plant are recovered from retail electric customers via a tracking mechanism, the IGCC rider.

The ninth semi-annual IGCC rider order was appealed by the Joint Intervenors. 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. On February 25, 2015, the IURC issued a new order upholding its prior decision and provided additional detailed findings. Joint Intervenors appealed this remand order to the Indiana Court of Appeals. On September 23, 2015, the Indiana Court of Appeals affirmed the IURC remand decision on one of the key financial issues. The Indiana Court of Appeals found that there was sufficient evidence for the IURC to find that the three-month delay in construction for this time period was not unreasonable and therefore the costs of such delay should be borne by Duke Energy Indiana customers. The Indiana Court of Appeals found that the IURC did not support its findings regarding the ratemaking impact of the tax in-service declaration and reversed and remanded this issue back to the IURC, with direction to hold further proceedings and issue additional findings on the issue. On December 10, 2015, the Indiana Court of Appeals denied a request for rehearing by Joint Intervenors, and the decision was not further appealed. The proceeding will be remanded to the IURC for further proceedings and additional findings on the tax in-service issue.

The 10th semi-annual IGCC rider order was also appealed by the Joint Intervenors. On August 21, 2014, the Indiana Court of Appeals affirmed the IURC order in the 10th IGCC rider proceeding and on October 29, 2014, denied the Joint Intervenors' request for rehearing. The Joint Intervenors requested the Indiana Supreme Court to review the decision, which was denied on April 23, 2015, concluding the appeal.

Duke Energy Indiana has filed the 14th and 15th semi-annual IGCC rider proceedings. The 11th through 15th semi-annual IGCC riders and a subdocket to Duke Energy Indiana's fuel adjustment clause are currently in various stages of approval by the IURC in the filing process. Issues in these filings include the determination whether the IGCC plant was properly declared in service for ratemaking purposes in June 2013 and a review of the operational performance of the plant. On September 17, 2015, Duke Energy Indiana, the Office of Utility Consumer Counselor, the Industrial Group and Nucor Steel Indiana reached a settlement agreement to resolve these pending issues. On January 15, 2016, The Citizens Action Coalition of Indiana, Inc., Sierra Club, Save the Valley and Valley Watch joined the settlement. The proposed settlement will result in customers not being billed for previously incurred operating costs of $87.5 million and for additional Duke Energy Indiana payments and commitments of $5.5 million for attorneys’ fees and amounts to fund consumer programs. Attorneys’ fees and expenses for the new settling parties will be addressed in a separate proceeding. Duke Energy Indiana recorded $87.5 million within Impairment charges and $5.5 million within Other Income and Expenses, net in the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2015. Duke Energy Indiana also recorded an $80.3 million reduction of Regulatory assets within Regulatory Assets and Deferred Debits, an additional $7.2 million of Other within Deferred Credits and Other Liabilities and $5.5 million of Accounts payable within Current Liabilities on the Consolidated Balance Sheets at December 31, 2015. Additionally, under the proposed settlement, the operating and maintenance expenses and ongoing maintenance capital at the plant are subject to certain caps during the years of 2016 and 2017. The revised settlement includes a commitment to either retire or stop burning coal by December 31, 2022 at the Gallagher Station. Pursuant to the settlement, the in-service date used for accounting and ratemaking will remain as June 2013. Remaining deferred costs will be recovered over eight years and not earn a carrying cost. The settlement is subject to IURC approval which is expected in the first half of 2016. As of December 31, 2015, deferred costs related to the project are approximately $128 million. Future IGCC riders will be filed annually, rather than every six months, with the next filing scheduled for first quarter 2017.

Duke Energy Indiana cannot predict the outcome of the settlement of these matters or future IGCC rider proceedings.

FERC Transmission Return on Equity Complaint

Customer groups have filed with the FERC complaints 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. The latest complaint, filed on February 12, 2015, claims the base rate of return on equity should be reduced to 8.67 percent and requests a consolidation of complaints. The motion to consolidate complaints was denied. On January 5, 2015, the FERC issued an order accepting the MISO transmission owners 0.50 percent adder to the base rate of return on equity based on participation in an RTO subject to it being applied to a return on equity that is shown to be just and reasonable in the pending return on equity complaint. A hearing in the base return on equity proceeding was held in August 2015. On December 22, 2015, the presiding FERC ALJ issued an Initial Decision in which he set the base rate of return on equity at 10.32 percent. The Initial Decision will be reviewed by the FERC. Duke Energy Indiana currently believes these matters will have an immaterial impact on its results of operations, cash flows and financial position.

Grid Infrastructure Improvement Plan

On August 29, 2014, pursuant to a new statute, 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. In May 2015, the IURC denied the original proposal due to an insufficient level of detailed projects and cost estimates in the plan. On December 7, 2015, Duke Energy Indiana filed a revised infrastructure improvement plan with an estimated cost of $1.8 billion in response to guidance from IURC orders and the Indiana Court of Appeals decisions related to this new statute. The revised plan uses a combination of advanced technology and infrastructure upgrades to improve service to customers and provide them with better information about their energy use. The plan is subject to approval of the IURC, with an order expected in July 2016. Duke Energy Indiana cannot predict the outcome of this matter.

Other Regulatory Matters

Atlantic Coast Pipeline

On September 2, 2014, Duke Energy, Dominion Resources (Dominion), Piedmont and AGL Resources announced the formation of a company, ACP, to build and own the proposed Atlantic Coast Pipeline (the pipeline), a 564-mile interstate natural gas pipeline. The pipeline is designed to meet the needs identified in requests for proposals by Duke Energy Carolinas, Duke Energy Progress and Piedmont. Dominion will build and operate the pipeline and has a 45 percent ownership percentage in ACP. Duke Energy has a 40 percent ownership interest in ACP through its Commercial Portfolio segment. Piedmont owns 10 percent and the remaining share is owned by AGL Resources. Duke Energy Carolinas and Duke Energy Progress, among others, will be customers of the pipeline. Purchases will be made under several 20-year supply contracts, 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. On September 18, 2015, ACP filed an application with the FERC requesting a CPCN authorizing ACP to construct the pipeline. ACP requested approval of the application by July 1, 2016, to enable construction to begin by September 2016, with an in-service date of on or before November 1, 2018. ACP is working with various agencies to develop the final pipeline route. ACP also requested approval of an open access tariff and the precedent agreements it entered into with future pipeline customers, including Duke Energy Carolinas and Duke Energy Progress.

On October 24, 2015, Duke Energy entered into a Merger Agreement with Piedmont. The ACP partnership agreement includes provisions to allow Dominion an option to purchase additional ownership interest in ACP to maintain a leading ownership percentage. Any change in ownership interests is not expected to be material to Duke Energy. Refer to Note 2 for further information related to Duke Energy's proposed acquisition of Piedmont.

Sabal Trail Transmission, LLC (Sabal Trail) Pipeline

On May 4, 2015, Duke Energy acquired a 7.5 percent ownership interest from Spectra Energy in the proposed 500-mile Sabal Trail natural gas pipeline. Spectra Energy will continue to own 59.5 percent of the Sabal Trail pipeline and NextEra Energy will own the remaining 33 percent. The Sabal Trail pipeline will traverse Alabama, Georgia and Florida to meet rapidly growing demand for natural gas in those states. The primary customers of the Sabal Trail pipeline, Duke Energy Florida and Florida Power & Light Company, have each contracted to buy pipeline capacity for 25-year initial terms. On February 3, 2016, the FERC issued an order granting the request for a CPCN to construct and operate the pipeline. The Sabal Trail pipeline requires additional regulatory approvals and is scheduled to begin service in 2017.

NC WARN FERC Complaint

On December 16, 2014, North Carolina Waste Awareness and Reduction Network (NC WARN) filed a complaint with the FERC against Duke Energy Carolinas and Duke Energy Progress that alleged (i) Duke Energy Carolinas and Duke Energy Progress manipulated the electricity market by constructing costly and unneeded generation facilities leading to unjust and unreasonable rates; (ii) 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; (iii) the plans of Duke Energy Carolinas and Duke Energy Progress for unrealistic future growth lead to unnecessary and expensive generating plants; (iv) the 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 (v) the FERC should force Duke Energy Carolinas and Duke Energy Progress to purchase power from other utilities rather than construct wasteful and redundant power plants. NC WARN also filed a copy of the complaint with the PSCSC on January 6, 2015. In April 2015, the FERC and the PSCSC issued separate orders dismissing the NC WARN petition. On May 14, 2015, NC WARN filed with FERC a motion for reconsideration which the FERC denied on November 19, 2015. This matter is now closed.

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.

Potential Coal Plant Retirements

The Subsidiary Registrants periodically file Integrated Resource Plans (IRP) with their state regulatory commissions. The IRPs provide a view of forecasted energy needs over a long term (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 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 retirement or included in recent IRPs as evaluated for potential retirement due to a lack of requisite environmental control equipment. Dollar amounts in the table below are included in Net property, plant and equipment on the Consolidated Balance Sheets.



	December 31, 2015
			Duke		Duke
	Duke		Energy		Energy
	Energy		Florida_(b)		Indiana_(c)
Capacity (in MW)	1,821		873		948
Remaining net book value (in millions)^(a)	$	352	$	131	$	221


(a)	Remaining net book value amounts presented exclude any capitalized asset retirement costs related to closure of ash basins.


(b)	Includes Crystal River Units 1 and 2. Progress Energy amounts are equal to Duke Energy Florida amounts.

(c)

Includes Wabash River Units 2 through 6 and Gallagher Units 2 and 4. Wabash River Unit 6 is being evaluated for potential conversion to natural gas. Duke Energy Indiana committed to retire or convert the Wabash River Units 2 through 6 by June 2018 in conjunction with a settlement agreement associated with the Edwardsport air permit. Duke Energy Indiana committed to either retire or stop burning coal at Gallagher Units 2 and 4 by December 31, 2022, as part of the proposed settlement of Edwardsport IGCC matters.

On October 23, 2015, the EPA published in the Federal Register the Clean Power Plan (CPP) rule for regulating carbon dioxide (CO₂) emissions from existing fossil fuel-fired electric generating units (EGUs). The CPP establishes CO₂ emission rates and mass cap goals that apply to fossil fuel-fired generation. Under the CPP, states are required to develop and submit a final compliance plan, or an initial plan with an extension request, to the EPA by September 6, 2016, or no later than September 6, 2018, with an approved extension. These state plans are subject to EPA approval, with a federal plan applied to states that fail to submit a plan to the EPA or if a state plan is not approved. Legal challenges to the CPP have been filed by stakeholders and motions to stay the requirements of the rule pending the outcome of the litigation were granted by the U.S. Supreme Court in February 2016. Final resolution of these legal challenges could take several years. Compliance with CPP could cause the industry to replace coal generation with natural gas and renewables, especially in states that have significant CO₂ reduction targets under the rule. Costs to operate coal-fired generation plants continue to grow due to increasing environmental compliance requirements, including ash management costs unrelated to CPP, and this may result in the retirement of coal-fired generation plants earlier than the current useful lives. Duke Energy continues to evaluate the need to retire generating facilities and plans to seek regulatory recovery, where appropriate, for amounts that have not been recovered upon asset retirements. However, recovery is subject to future regulatory approval, including the recovery of carrying costs on remaining book values, and therefore cannot be assured.

Refer to the "Western Carolinas Modernization Plan" discussion above for details of Duke Energy Progress' planned retirements.