REGULATORY MATTERS

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, Kentucky and Indiana), as well as sales of transmission service.

Duke Energy Carolinas and Duke Energy Progress

Ash Basin Closure Costs Deferral

On July 13, 2016, in response to a joint petition of Duke Energy Carolinas and Duke Energy Progress, the PSCSC issued an accounting order for the deferment into a regulatory account of certain costs incurred in connection with federal and state environmental remediation requirements related to the permanent closure of ash basins and other ash storage units at coal-fired generating facilities that have provided or are providing generation to customers located in South Carolina. The decision allows for ash basin closure expenses to be partially offset with excess regulatory liability amounts from the deferral of nuclear decommissioning costs that are collected from South Carolina retail customers and for Duke Energy Progress to offset incurred ash basin closure costs with costs of removal amounts collected from customers. The PSCSC's ruling does not change retail rates or the tariff amounts and in no way limits the PSCSC's ability to challenge the reasonableness of expenditures in subsequent proceedings.

FERC Transmission Return on Equity Complaints

On January 7, 2016, a group of transmission service customers filed a complaint with 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. On the same date, a similar complaint was filed with FERC claiming 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. On April 21, 2016, FERC issued an order which consolidated the cases, set a refund effective date of January 7, 2016, and set the consolidated case for settlement and hearing. On June 14, 2016, Duke Energy Carolinas and Duke Energy Progress reached a settlement agreement in principle to reduce the return on equity for both companies to 10 percent. On August 19, 2016, Duke Energy Carolinas and Duke Energy Progress filed for FERC approval of the settlement agreement. Duke Energy Carolinas and Duke Energy Progress do not expect the potential impact on results of operations, cash flows or financial position to be material.

Duke Energy Carolinas

Advanced Metering Infrastructure Deferral

On July 12, 2016, the PSCSC issued an accounting order for Duke Energy Carolinas to defer the financial effects of depreciation expense incurred for the installation of advanced metering infrastructure (AMI) meters, the carrying costs on the investment at its weighted average cost of capital and the carrying costs on the deferred costs at its weighted average cost of capital not to exceed $45 million. The decision also allows Duke Energy Carolinas to continue to depreciate the non-AMI meters to be replaced. Current retail rates will not change as a result of the decision and the PSCSC's ability to challenge the reasonableness of expenditures in subsequent proceedings is not limited.

William States Lee Combined Cycle Facility

On April 9, 2014, the PSCSC granted Duke Energy Carolinas and North Carolina Electric Membership Corporation (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 allowance for funds used during construction (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 (SCCL) and Southern Alliance for Clean Energy (SACE) jointly filed a Notice of Appeal with the Court of Appeals of South Carolina (S.C. Court of Appeals) 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 S.C. Court of Appeals affirmed the PSCSC's decision on February 10, 2016, and on March 24, 2016, denied a request for rehearing filed by SCCL and SACE. On April 21, 2016, SCCL and SACE petitioned the South Carolina Supreme Court for review of the S.C. Court of Appeals decision. Duke Energy Carolinas filed its response on June 13, 2016, and SCCL and SACE filed a reply on June 23, 2016. On September 6, 2016, the Small Business Chamber of Commerce filed a motion for permission to file a brief supporting the environmental intervenors’ position. On September 22, 2016, the South Carolina Supreme Court granted permission for the brief, and allowed Duke Energy Carolinas an opportunity to file a response, which was filed on October 3, 2016. Duke Energy Carolinas cannot predict the outcome of this matter.

Duke Energy Progress

South Carolina Rate Case

On July 1, 2016, Duke Energy Progress filed an application with the PSCSC requesting an average 14.5 percent increase in retail revenues. The requested rate change would increase annual revenues by approximately $79 million, with a rate of return on equity of 10.75 percent. The increase is designed to recover the cost of investment in new generation infrastructure, environmental expenditures including allocated historical ash basin closure costs and increased nuclear operating costs. Duke Energy Progress has requested new rates to be effective January 1, 2017. On October 19, 2016, Duke Energy Progress, the ORS and intervenors entered into a settlement agreement that was filed with the PSCSC on the same day. Terms of the settlement agreement include an approximate $56 million increase in revenues over a two-year period. An increase of approximately $38 million in revenues would be effective January 1, 2017, and an increase of approximately $18.5 million in revenues would be effective January 1, 2018. Duke Energy Progress will amortize approximately $18.5 million from the cost of removal reserve in 2017. Other settlement terms include a rate of return on equity of 10.1 percent, agreement to implement nuclear levelization accounting in South Carolina, and ongoing deferral of allocated ash basin closure costs from July 1, 2016, until the next base rate case. The settlement also provides that Duke Energy Progress will not seek an increase in rates in South Carolina to occur prior to 2019, with limited exceptions. A hearing was held on October 31, 2016. Duke Energy Progress cannot predict the outcome of this matter.

Western Carolinas Modernization Plan

On November 4, 2015, in response to community feedback, Duke Energy Progress announced a revised Western Carolinas Modernization Plan with an estimated cost of $1.1 billion. The revised plan includes retirement of the existing Asheville coal-fired plant, the construction of 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 Certificate of Public Convenience and Necessity (CPCN) with the NCUC for the new natural gas units on January 15, 2016. On March 28, 2016, the NCUC issued an order approving the CPCN for the new combined-cycle natural gas plants, but denying the CPCN for the contingent simple cycle unit without prejudice to Duke Energy Progress to refile for approval in the future. Site preparation activities are underway and construction of these plants is scheduled to begin in early 2017. The plants are expected to be in service by late 2019. Duke Energy Progress plans to file for future approvals related to the proposed solar generation and pilot battery storage project.

On May 27, 2016, N.C. Waste Awareness and Reduction Network (NC WARN) and The Climate Times filed a notice of appeal from the CPCN order to the N.C. Court of Appeals. On May 31, 2016, Duke Energy Progress filed a motion to dismiss the notice of appeal with the NCUC due to NC WARN's and The Climate Times' failure to post a required appeal bond. After a series of filings, an NCUC order, petitions to the N.C. Court of Appeals and an evidentiary hearing, on July 8, 2016, the NCUC issued an order setting NC WARN's and The Climate Times' appeal bond at $98 million. On July 28, 2016, NC WARN and The Climate Times filed a notice of appeal and exceptions from the NCUC's July 8, 2016, appeal bond order. On August 2, 2016, the NCUC granted Duke Energy Progress' motion to dismiss NC WARN's and The Climate Times' notice of appeal from the CPCN order due to failure to post the requisite bond. On August 18, 2016, NC WARN and The Climate Times filed a petition with the N.C. Court of Appeals seeking appellate review of the NCUC’s CPCN order, the July 8, 2016, appeal bond order and the August 2, 2016, order dismissing their notice of appeal, which the N.C. Court of Appeals denied on September 6, 2016. On September 19, 2016, the NCUC granted Duke Energy Progress' motion to dismiss NC WARN's and The Climate Times' subsequent appeal of the second bond order dated July 28, 2016, and NC WARN's and The Climate Times' subsequent appeal of the CPCN order and dismissal order dated August 18, 2016. On October 17, 2016, NC WARN and The Climate Times filed another petition for review with the N.C. Court of Appeals asking the court to reverse the CPCN order, the second bond order and the dismissal of their first and second notices of appeal as to the CPCN order. Duke Energy Progress cannot predict the outcome of this matter.

The carrying value of the 376 MW Asheville coal-fired plant, including associated ash basin closure costs, of $562 million and $548 million are included in Generation facilities to be retired, net on Duke Energy Progress' Condensed Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015, respectively.

Duke Energy Florida

Hines Chiller Uprate Project

On May 20, 2016, Duke Energy Florida filed a petition seeking approval to include in base rates the revenue requirement for a Chiller Uprate Project (Uprate Project) at the Hines station. Duke Energy Florida proposed to complete the Uprate Project in two phases: Phase one to include work on Hines Units 1-3 and common equipment, to be placed in service during October 2016; and Phase two work on Hines Unit 4 to be placed in service during January 2017. The final combined construction cost estimate for both phases of approximately $150 million is below the cost estimate provided during the need determination proceeding. Duke Energy Florida estimated an annual retail revenue requirement for Phase one and Phase two of approximately $17 million and $3 million, respectively. On August 29, 2016, the FPSC approved the Phase one revenue requirement to be effective in customer rates in November 2016. However, Duke Energy Florida made filings with the FPSC in October 2016 to remove the Uprate Project from customer rates because a portion of the common equipment required for either phase to be considered in-service will not be completed as expected. Duke Energy Florida is evaluating the potential impact to cost estimates related to the delay of the project. Duke Energy Florida will file for recovery of the costs associated with the Uprate Project at a later date. Duke Energy Florida cannot predict the outcome of this matter.

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. In July 2015, the FERC and the FPSC issued separate orders of approval for the Osprey Plant acquisition. The Hart-Scott-Rodino waiting period expired on May 2, 2016. Closing of the acquisition is expected to occur in January 2017, upon the expiration of an existing Power Purchase Agreement between Calpine and Duke Energy Florida. In anticipation of closing, on August 29, 2016, Duke Energy Florida filed a petition seeking approval to include in base rates the revenue requirements for the Osprey Plant acquisition to be included in customer bills beginning in February 2017. Duke Energy Florida estimates the retail revenue requirements for the Osprey acquisition to be approximately $48 million. On November 1, 2016, the FPSC approved the Osprey Plant acquisition and the petition to include the revenue requirements in base rates.

Crystal River Unit 3 Regulatory Asset

In June 2015, the governor of Florida signed legislation to allow utilities to issue nuclear asset-recovery bonds to finance the recovery of certain retired nuclear generation assets, with approval of the FPSC. In November 2015, the FPSC issued a financing order approving Duke Energy Florida’s request to issue nuclear asset-recovery bonds to finance its unrecovered regulatory asset related to Crystal River Unit 3 (Crystal River 3) through a wholly owned special purpose entity. Nuclear asset-recovery bonds replace the base rate recovery methodology authorized by the 2013 Revised and Restated Stipulation and Settlement Agreement (2013 Agreement) and result in a lower rate impact to customers with a recovery period of approximately 20 years.

Pursuant to provisions in Florida Statutes and the FPSC financing order, in 2016, Duke Energy Florida formed Duke Energy Florida Project Finance, LLC (DEFPF), a wholly owned, bankruptcy remote special purpose subsidiary for the purpose of issuing nuclear asset-recovery bonds. In June 2016, DEFPF issued $1,294 million aggregate principal amount of senior secured bonds (nuclear asset-recovery bonds) to finance the recovery of Duke Energy Florida's Crystal River 3 regulatory asset.

In connection with this financing, net proceeds to DEFPF of approximately $1,287 million, after underwriting costs, were used to acquire nuclear asset-recovery property from Duke Energy Florida and to pay transaction related expenses. The nuclear asset-recovery property includes the right to impose, bill, collect and adjust a non-bypassable nuclear asset-recovery charge, to be collected on a per kilowatt-hour basis from all Duke Energy Florida retail customers until the bonds are paid in full. Duke Energy Florida began collecting the nuclear asset-recovery charge on behalf of DEFPF in customer rates in July 2016.

See Notes 6 and 13 for additional information.

Duke Energy Ohio

Base Rate Case

In connection with Duke Energy Ohio’s deployment of SmartGrid network, consisting of investments in AMI and distribution automation, a rider was established to recover these investments and return expected savings to customers. A stipulation in establishing this rider was approved by the PUCO in 2012, whereby Duke Energy Ohio committed to filing a base electric distribution case within one year of full deployment of SmartGrid. On October 22, 2015, PUCO staff concluded that full deployment had occurred thereby, absent relief by the PUCO, Duke Energy Ohio would be required to file a base electric rate case proceeding no later than October 22, 2016. A number of proceedings have been initiated by the PUCO related to continued development of retail markets in Ohio including questions related to demand-side management, time-differentiated pricing and AMI that would impact such a base rate filing. On September 15, 2016, Duke Energy Ohio requested the PUCO approve a waiver of the condition in the 2012 stipulation to file a base rate case. On September 22, 2016, the Office of the Ohio Consumers' Counsel filed an objection to the waiver request and, on October 12, 2016, PUCO Staff filed a reply proposing a filing date no later than July 21, 2017. Duke Energy Ohio cannot predict the outcome of this matter.

Natural Gas Pipeline Extension

Duke Energy Ohio is proposing to install a new natural gas pipeline in its Ohio service territory to increase system reliability and enable the retirement of older infrastructure. The proposed project involves the installation of a natural gas line and is estimated to cost between $86 million and $110 million, excluding AFUDC. On September 13, 2016, Duke Energy Ohio filed with the Ohio Power Siting Board for approval of one of two proposed routes. If approved, construction of the pipeline extension is expected to be completed by early 2019.

Advanced Metering Infrastructure

On April 25, 2016, Duke Energy Kentucky filed with the KPSC an application for approval of a CPCN for the construction of AMI. Duke Energy Kentucky anticipates that the estimated $49 million project, if approved, will take about two years to complete. Duke Energy Kentucky also requested approval to establish a regulatory asset of approximately $10 million for the remaining book value of existing meter equipment and inventory that will be replaced. On July 20, 2016, the Kentucky Attorney General, the only intervenor in the proceeding, moved to dismiss the application. Duke Energy Kentucky filed its opposition to the Kentucky Attorney General's motion to dismiss on July 27, 2016. On September 28, 2016, the KPSC denied the Kentucky Attorney General's motion to dismiss and granted Duke Energy Kentucky's motion to file rebuttal testimony. An evidentiary hearing is scheduled for December 1, 2016. Duke Energy Kentucky cannot predict the outcome of this matter.

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). Under the ASRP, Duke Energy Ohio proposed to replace certain natural gas service lines on an accelerated basis over a 10-year period. Duke Energy Ohio also proposed 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's current projected total capital and operations and maintenance expenditures under the ASRP is approximately $240 million. The filing also sought approval of Rider ASRP to recover related expenditures. Duke Energy Ohio proposed to update Rider ASRP on an annual basis. Intervenors opposed the ASRP, primarily because they believe the program is neither required nor necessary under federal pipeline regulation. On October 26, 2016, the PUCO issued an order denying the proposed ASRP. The PUCO did, however, encourage Duke Energy Ohio to work with the PUCO Staff and intervenors to identify a reasonable solution for the risks attributed to service line leaks caused by corrosion. Duke Energy Ohio is currently evaluating the order.

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. The PUCO granted the applications for rehearing filed by Duke Energy Ohio and an intervenor on July 8, 2015. 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 the stipulation, in December 2015, Duke Energy Ohio re-established approximately $20 million of revenues that had been reversed in the second quarter of 2015. On October 26, 2016, the PUCO issued an order approving the stipulation without modification.

2012 Natural Gas Rate Case/Manufactured Gas Plant Cost Recovery

On November 13, 2013, the PUCO issued an order (PUCO order) approving a settlement of Duke Energy Ohio’s natural gas base rate case and authorizing the recovery of costs incurred between 2008 and 2012 for environmental investigation and remediation of two former manufactured gas plant (MGP) sites. The PUCO order also authorized Duke Energy Ohio to continue deferring MGP environmental investigation and remediation costs incurred subsequent to 2012, and to submit annual filings to adjust the MGP rider for future costs. Intervening parties appealed this decision to the Ohio Supreme Court and that appeal remains pending. Oral argument is scheduled for February 28, 2017. Investigation and remediation expenses at these MGP sites that have not been collected through the MGP rider are approximately $101 million and are recorded as Regulatory assets on Duke Energy Ohio's Condensed Consolidated Balance Sheet as of September 30, 2016.

The PUCO order also contained deadlines for completing the MGP environmental investigation and remediation costs at the MGP sites. For the property known as the East End site the PUCO order established a deadline of December 31, 2016. As of September 30, 2016, $46 million of the regulatory asset represents future remediation cost expected to be incurred at the East End site after 2016. The PUCO order authorized Duke Energy Ohio to seek to extend these deadlines due to certain circumstances. On May 16, 2016, Duke Energy Ohio filed an application to extend the deadline for cost recovery applicable to the East End site. The PUCO set a procedural schedule for filing comments on the application and associated replies for November 23, 2016, and December 2, 2016, respectively.

Duke Energy Ohio cannot predict the outcome of this matter.

Regional Transmission Organization Realignment

Duke Energy Ohio, including Duke Energy Kentucky, transferred control of its transmission assets from Midcontinent Independent System Operator, Inc. (MISO) to PJM Interconnection, LLC (PJM), effective December 31, 2011. The PUCO approved a settlement related to Duke Energy Ohio’s recovery of certain costs of the Regional Transmission Organization (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. The KPSC also approved a 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.

Duke Energy Ohio had a recorded liability for its exit obligation and share of MTEP costs, excluding MVP, of $91 million and $92 million, respectively, at September 30, 2016 and December 31, 2015, within Other in Current liabilities and Other in Deferred credits and other liabilities on Duke Energy Ohio’s Condensed Consolidated Balance Sheets. The retail portions of MTEP costs billed by MISO are recovered by Duke Energy Ohio through a non-bypassable rider. As of September 30, 2016 and December 31, 2015, Duke Energy Ohio had $72 million recorded in Regulatory assets on the Condensed Consolidated Balance Sheets.

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 May 19, 2016, the FERC denied the request for rehearing filed by MISO and the MISO Transmission Owners. On July 15, 2016, the MISO Transmission Owners filed a petition for review with the U.S. Court of Appeals for the Sixth Circuit. Duke Energy Ohio cannot predict the outcome of this matter.

Duke Energy Indiana

Coal Combustion Residual Plan

On March 17, 2016, Duke Energy Indiana filed with the IURC a request for approval of its first group of federally mandated Coal Combustion Residual (CCR) rule compliance projects (Phase I CCR Compliance Projects) to comply with the U.S. Environmental Protection Agency's (EPA) CCR rule. The projects in this Phase I filing are CCR compliance projects, including the conversion of Cayuga and Gibson Stations to dry bottom ash handling and related water treatment. Duke Energy Indiana has requested timely recovery of approximately $380 million in retail capital costs and incremental operating and maintenance costs under a federal mandate tracker which provides for timely recovery of 80 percent of such costs and deferral with carrying costs of 20 percent of such costs for recovery in a subsequent retail base rate case. An evidentiary hearing is scheduled for February 2017. Duke Energy Indiana cannot predict the outcome of this matter.

Edwardsport Integrated Gasification Combined Cycle Plant

On November 20, 2007, the IURC granted Duke Energy Indiana a CPCN for the construction of the Edwardsport Integrated Gasification Combined Cycle (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 (IGCC rider).

The ninth semi-annual IGCC rider order was appealed by the Joint Intervenors. The proceeding has been remanded to the IURC for further proceedings and additional findings on the tax in-service issue. An evidentiary hearing was held on September 13, 2016, and an order is expected by early 2017. Duke Energy Indiana cannot predict the outcome of this matter.

The 11th through 15th semi-annual IGCC riders and a subdocket to Duke Energy Indiana's fuel adjustment clause were approved by the IURC as part of an August 2016 settlement agreement. Issues in these filings included 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 a revised settlement (IGCC settlement). The IGCC settlement resulted 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 recognized pretax impairment and related charges of $93 million in 2015. Additionally, under the IGCC settlement, the recovery of operating and maintenance expenses and ongoing maintenance capital at the plant are subject to certain caps during the years of 2016 and 2017. The IGCC settlement also includes a commitment to either retire or stop burning coal by December 31, 2022, at the Gallagher Station. Pursuant to the IGCC 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. On August 24, 2016, the IURC approved the settlement in full with no changes or conditions. The order was not appealed and the proceeding is concluded. As of September 30, 2016, deferred costs related to the project are approximately $184 million. Under the IGCC settlement, future IGCC riders will be filed annually, rather than every six months, with the next filing scheduled for first quarter 2017.

FERC Transmission Return on Equity Complaint

Customer groups have filed with 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, 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 complaints. A hearing in the base return on equity proceeding was held in August 2015. On December 22, 2015, the presiding FERC ALJ in the first complaint issued an Initial Decision in which he set the base rate of return on equity at 10.32 percent. On September 28, 2016, the Initial Decision in the first complaint was affirmed by FERC. On June 30, 2016, the presiding FERC ALJ in the second complaint issued an Initial Decision setting the base rate of return on equity at 9.70 percent. The Initial Decision in the second complaint is pending FERC review. Duke Energy Indiana currently believes these matters will not have a material 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. The plan also provided for cost recovery through a transmission and distribution rider (T&D Rider). 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. It also provides for cost recovery through a T&D Rider. In March 2016, Duke Energy Indiana entered into a settlement with all parties to the proceeding except the Citizens Action Coalition of Indiana, Inc. The settlement agreement decreased the capital expenditures eligible for timely recovery of costs in the seven-year plan to approximately $1.4 billion, including the removal of an AMI project. Under the settlement, the return on equity to be used in the T&D Rider is 10 percent. The IURC approved the settlement and issued a final order on June 29, 2016. The order was not appealed, and the proceeding is concluded.

The settlement also provided for deferral accounting for depreciation and post-in-service carrying costs for AMI projects outside the seven-year plan. Duke Energy Indiana withdrew its request for a regulatory asset for current meters and will retain any savings associated with future AMI installation until the next retail base rate case, which is required to be filed prior to the end of the seven-year plan. During the third quarter of 2016, Duke Energy Indiana decided to implement the AMI project. This decision resulted in a pretax impairment charge related to existing or non-AMI meters of approximately $8 million for the three and nine months ended September 30, 2016, based in part on the requirement to file a base rate case in 2022 under the approved T&D Rider plan. As of September 30, 2016, Duke Energy Indiana's remaining net book value of non-AMI meters is approximately $48 million and will be depreciated through 2022. In the event that Duke Energy Indiana were to file a base rate case earlier than 2022, it may result in additional impairment charges.

OTHER REGULATORY MATTERS

Atlantic Coast Pipeline

On September 2, 2014, Duke Energy, Dominion Resources (Dominion), Piedmont and Southern Company Gas, formerly AGL Resources Inc., 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 originally owned a 45 percent ownership percentage in ACP. Duke Energy owned a 40 percent ownership interest in ACP through its Commercial Portfolio segment. Piedmont owned 10 percent and the remaining share was owned by Southern Company Gas.

On October 3, 2016, Duke Energy and Piedmont completed a merger transaction that resulted in Piedmont becoming a wholly owned subsidiary of Duke Energy. In connection with this transaction, and pursuant to terms of the ACP partnership agreement, Piedmont transferred 3 percent of its interest in ACP to Dominion in exchange for approximately $14 million. As a result of this transfer, Dominion maintains a leading ownership percentage of 48 percent and Duke Energy has a combined ownership percentage of 47 percent. See Note 2 for additional information related to Duke Energy's acquisition of Piedmont.

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. In August 2016, FERC issued a Notice of Schedule indicating a final Environmental Impact Statement (EIS) will be issued by June 30, 2017. FERC approval of the application is expected within 90 days of the issuance of the final EIS. Construction is projected to begin once FERC approval is received with a targeted in-service date in the second half of 2019. ACP executed a construction agreement in September 2016 and 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.

Sabal Trail Transmission, LLC 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 (FP&L), 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 Sabal Trail pipeline. The Sabal Trail pipeline has received regulatory approvals and initiated construction of the pipeline with an expected in-service date in mid-2017.

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. 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.

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 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. The 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. The costs to comply with this order are not material. FERC also referred Duke Energy’s failure to expressly designate the phase shifter reactivation as a mitigation project in the original mitigation plan filing in March 2012 to the FERC Office of Enforcement for further inquiry. In response, and since December 2014, the FERC Office of Enforcement has been conducting a nonpublic investigation of Duke Energy's market power analyses included in the Progress merger filings submitted to FERC. Duke Energy cannot predict the outcome of this investigation.

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 because 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 Condensed Consolidated Balance Sheets as of September 30, 2016.



		Remaining Net
	Capacity	Book Value^(a)
	(in MW)	(in millions)
Progress Energy and Duke Energy Florida
Crystal River Units 1 and 2	873	123
Duke Energy Indiana
Wabash River Unit 6^(b)	318	33
Gallagher Units 2 and 4^(c)	280	137
Total Duke Energy	1,471	293


(a)	Remaining net book value amounts exclude any capitalized asset retirement costs.

(b)

In April 2016, Wabash River 6 terminated coal burning operations and is targeted for retirement by the end of 2016. The total net book value of $90 million for the retail portion of Wabash River Unit 6 and the retail portion of capitalized asset retirement costs for Wabash River Units 2 through 6 is classified as Generation facilities to be retired, net on Duke Energy Indiana's Condensed Consolidated Balance Sheet at September 30, 2016.


(c)	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 settlement of Edwardsport IGCC matters.

On October 23, 2015, the EPA published in the Federal Register the final Clean Power Plan (CPP) rule regulating carbon dioxide (CO2) emissions from existing fossil fuel-fired electric generating units. The CPP establishes CO2 emission rates and mass cap goals that apply to existing fossil fuel-fired electric generation units. Under the CPP, states were required to develop and submit a final compliance plan, or an initial plan with an extension request, to the EPA by September 6, 2016. States that receive an extension must submit a final completed plan to the EPA by September 6, 2018. 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 final CPP have been filed by stakeholders. On February 9, 2016, the U.S. Supreme Court issued a stay of the final CPP rule, halting implementation until legal challenges are resolved. 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, which may result in the retirement of coal-fired generation plants earlier than the current end of 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.