Brian D. Savoy

SVP, Chief Accounting Officer and Controller

550 South Tryon Street

Mail Code: DEC 44-A

Charlotte, NC 28202

o: 704-382-6242

f: 980-373-6797

June 26, 2015

VIA EDGAR

Jennifer Thompson

Accounting Branch Chief

Division of Corporation Finance

U.S. Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

Re:     Duke Energy Corporation

Duke Energy Carolinas, LLC

Progress Energy, Inc.

Duke Energy Progress, Inc.

Duke Energy Florida, Inc.

Duke Energy Ohio, Inc.

Duke Energy Indiana, Inc.

Form 10-K for the Fiscal Year Ended December 31, 2014

Filed March 2, 2015

File Nos. 001-32853, 001-04928, 001-15929, 001-03382, 001-03274,

001-01232 & 001-03543

Dear Ms. Thompson:

On behalf of Duke Energy Corporation, collectively with its subsidiaries ("Duke Energy" or the "Company"), we have the following responses to your comment letter dated June 12, 2015, relating to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

For your convenience, we have included the comment of the staff (the "Staff") of the Securities and Exchange Commission (the "Commission") below in bold followed by Duke Energy's corresponding response.

Duke Energy Corporation

General

1. In the interest of reducing the number of comments, we have not repeated Duke Energy comments that also relate to the other Duke Energy Registrants, including Duke Energy Carolinas, Progress Energy, Duke Energy Progress, Duke Energy Florida, Duke Energy Ohio and Duke Energy Indiana. Please apply all Duke Energy comments to the other Duke Energy Registrants separately to the extent they are applicable.

As requested, the following responses are made with acknowledgment that the comments are applied to all Duke Energy Registrants to the extent they are applicable.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 2

Form 10-K for the Fiscal Year Ended December 31, 2014

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

Income (Loss) From Discontinued Operations, Net of Tax, page 46

2. You disclose on page 46 that discontinued operations were impacted by a $134 million pretax mark-to-market loss on economic hedges. Please reconcile this explanation with your page 174 disclosure of a $729 million loss recognized in "Income (Loss) From Discontinued Operations." Additionally, please tell us the primary factors contributing to this loss recognized during the fiscal year ended December 31, 2014 and clarify if the derivative amounts recorded within discontinued operations wholly relate to positions directly held by the disposal group or if the amounts also include indirect allocations from corporate or other areas of your business.

Derivative contracts are used to hedge a portion of the economic value of the Company's generation assets within the nonregulated Midwest generation disposal group. Neither hedge accounting nor regulatory treatment is applied to these derivatives as they are considered economic hedges of the nonregulated generation assets and, as such, the realized gains and losses on the derivatives and the economic gain or loss from the changes in electricity prices for electricity sold by these generating assets are both recognized in reported net income when realized or settled. Therefore, realized gains and losses on these derivatives are not a key driver to income/loss variances between years. The unrealized gains and losses on these derivatives are adjusted to fair value and recorded in reported earnings at each balance sheet date. Management believes disclosure of unrealized net gains and losses in the context of a variance driver for the discontinued operating results is most meaningful in understanding the impacts of derivative contracts to the reported results for discontinued operations.

The Company reported on page 46 that Discontinued Operations results decreased $662 million for the year ended December 31, 2014, compared to the same period in 2013. A driver of that variance was the $134 million of 2014 unrealized net losses reflected in earnings, related to the net loss on derivative positions associated with the nonregulated Midwest generation disposal group. The $729 million net loss recognized in "Income (Loss) from Discontinued Operations," and reported on page 174, represents both realized and unrealized net losses during the year recognized on derivatives of the Midwest generation disposal group. The primary reasons for the derivative losses were volatile commodity prices due to extreme weather and demand caused by the polar vortex in the Midwest region, and generally higher power prices from the time the derivative was executed until settled. No indirect allocations of derivatives from corporate or other areas of our business were made to discontinued operations.

In preparing the response to this inquiry we identified errors in Duke Energy's and Duke Energy Ohio's disclosures on page 174 and page 183, respectively. The amounts disclosed of $729 million (page 174) and $758 million (page 183) as net losses on commodity contracts recognized in the income statement line item “Income (Loss) From Discontinued Operations” should have been reported as $412 million and $434 million, respectively. These errors did not impact the MD&A variance analysis associated with unrealized losses described above.

We evaluated these errors under the guidance of ASC 250-10-S99, whereby:

“Materiality concerns the significance of an item to users of a registrant's financial statements. A matter is "material" if there is a substantial likelihood that a reasonable person would consider it important. In its Concepts Statement 2, Qualitative Characteristics of Accounting Information, the FASB stated the essence of the concept of materiality as follows:

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 3

• The omission or misstatement of an item in a financial report is material if, in the light of surrounding circumstances, the magnitude of the item is such that it is probable that the judgment of a reasonable person relying upon the report would have been changed or influenced by the inclusion or correction of the item."

The only impact of the error is a disclosure error in Note 14, Derivatives and Hedging. As discussed above, the disclosure overstates the amount of derivative losses from commodity contracts included in the “Income (Loss) From Discontinued Operations” financial statement line item with the adjusted or corrected amounts still a reported net loss. Most importantly, the errors do not impact the financial statements, including the reported results of the discontinued operations, nor any terms and conditions of the sale of the disposal group (as disclosed on page 125-126, Note 2 Acquisitions, Dispositions and Sales of Other Assets). Based on this analysis, we do not consider these errors to be material.

As to the status of the discontinued operations, we disclosed in Note 2 the sale of the disposal group was expected to be completed "by the end of the second quarter of 2015," and in fact it closed in early April 2015. Therefore, future Company filings will not include ongoing derivative activity related to the sold business.

Duke Energy Indiana

Results of Operations

Operating Expenses, page 55

3. You disclose on page 55 that Duke Energy Indiana’s property and other taxes increased by $57 million, primarily as a result of amounts recorded related to an Indiana sales tax audit. Please tell us more about this matter, including if it represents an error, and, if so, how you assessed it under ASC 250 as it relates to the financial statements of Duke Energy Indiana.

Tax-exempt status determines whether a purchaser is able to make sales tax-free purchases that normally would be subject to sales tax. Based on customer service applications and the best available information regarding the tax-exempt status of the customer, we bill and collect Indiana sales tax from customers and then remit these collections to the Indiana Department of Revenue (IDOR). A sales tax audit performed by the IDOR covering the period January 1, 2009 through December 31, 2011, included a review of the information related to the tax-exempt status of customers. This audit by the IDOR resulted in a preliminary assessment of a tax deficiency for this three-year period. The IDOR based its preliminary assessment of a tax deficiency for this period on statistical sampling and their determination of tax-exempt status, and then extrapolated a non-compliance rate from the sample to all reported exempt sales as reported by Duke Energy Indiana during the three-year audit period. The results of this audit were shared with the Company in 2014. We concluded based on work performed in addressing the audit findings and discussions with IDOR, including settlement negotiations, that a liability was in fact probable and could be estimated, not only for the period under audit but also for all reported periods subsequent to the audit. An ASC 450 liability was accrued during 2014 when both conditions were met that a loss was probable and estimable. ASC 250-10-20 defines an error in previously issued financial statements as “An error in recognition, measurement, presentation, or disclosure in financial statements resulting from mathematical mistakes, mistakes in the application of generally accepted accounting principles (GAAP), or oversight or misuse of facts that existed at the time the financial statements were prepared.” We do not believe this matter meets the definition of an error under the literature because the audit findings relate to the interpretation of customers' tax-exempt status, and therefore, we did not complete an assessment of the matter under ASC 250.

Critical Accounting Policies, page 55

4. Please tell us what consideration you gave to including a critical accounting policies and estimates discussion of your asset retirement obligations. Refer to Section V of SEC Release No. 33-8350.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 4

Prior to 2014, the Duke Energy Registrants primarily recorded asset retirement obligations related to decommissioning nuclear power facilities, asbestos removal and closure of landfills at fossil generation facilities. For the year ended December 31, 2014, there was an increase in such obligations for estimated ash basin closure costs as a result of the North Carolina Coal Ash Management Act of 2014 (CAMA or the Act). Substantially all of the asset retirement obligations are primarily associated with the Company’s rate-regulated operations and have regulatory accounting offsets based on the expectation of prospective or ongoing recovery from customers. Changes in estimates of our asset retirement obligations do not have a significant impact on our results of operations or financial condition (Section V of SEC Release No. 33-8350). However, recovery of such amounts is considered a critical accounting judgment and is disclosed in detail in MD&A within Critical Accounting Policies and Estimates under the heading of Regulatory Accounting. The Company also considered other 2014 Form 10-K disclosures including Summary of Significant Accounting Policies (see pages 115 and 118 of the 2014 Form 10-K) and Asset Retirement Obligations (see pages 161-163 of the 2014 Form 10-K) that detail the accounting for asset retirement obligations estimates and regulatory accounting offsets.

Liquidity and Capital Resources

Cash Flows from Operating Activities, page 61

5. We note your disclosure of your intention to indefinitely reinvest prospective undistributed earnings generated by your foreign subsidiaries, and your disclosure on page 229 that you will not provide for U.S. taxes for those earnings. In future filings, ensure your Liquidity and Capital Resources disclosures state that you will not provide for U.S. taxes on these prospective earnings and that you would be required to accrue taxes on these earnings if they were repatriated.

The Company agrees that for future filings, beginning with the June 30, 2015 Form 10-Q, we will disclose in the Liquidity and Capital Resources section that we are not providing U.S. taxes on foreign earnings that we plan to indefinitely reinvest and that we would be required to accrue these taxes on these foreign earnings if they were repatriated.

Restrictive Debt Covenants, page 61

6. You disclose that you were in compliance with all covenants related to your significant debt agreements. Please tell us what you mean by "significant" as it relates to debt agreements. Additionally, please tell us and disclose whether there were violations of covenants as of December 31, 2014 related to debt agreements other than those you deemed "significant" that are material to an understanding of your liquidity and capital resources.

Reference to the word "significant" in this context was used to describe a debt agreement that is material in any manner for an understanding of the Company's liquidity and capital resources. Except for a minor condition of noncompliance for capital lease agreements with less than $15 million outstanding there were no violations of debt covenants as of December 31, 2014. As a result, we did not consider these agreements to be material and necessary to gain an understanding of Duke Energy's liquidity and capital resources. Duke Energy believes its use of the adjective "significant" when referring to compliance with debt agreements was appropriate under these circumstances.

Item 8. Financial Statements and Supplementary Data

Consolidated Statements of Cash Flows, page 81

7. We note your disclosure on page 151 regarding proceeds received in September 2014 related to spent nuclear fuel lawsuits, including the amounts you received and that they were treated as a reduction to capital costs associated with your construction of on-site storage facilities. Please tell us how these proceeds were presented in your consolidated statements of cash flows and, if presented net of other items, how such presentation complies with ASC 230-10-45-7.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 5

The proceeds related to spent nuclear fuel lawsuits received in September 2014 are classified as Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows as they are directly related to investing activities (ASC 230-10-45-16c). These proceeds were presented as a net reduction of capital expenditures. The regulatory rate treatment of the recovery of these claims is a direct offset and recovery of related capital expenditures. The Company acknowledges the guidance provided in ASC 230-10-45-7 that a gross presentation generally provides more meaningful insight into the business and operations of an entity and if material, the Company agrees the amounts should be shown as a separate line item within the investing activities. However, these proceeds were presented as a net reduction to capital expenditures based on the regulatory rate treatment of these recoveries and the immaterial significance of these amounts relative to the overall cash flows for investing activity of the respective registrants. The amount of spent nuclear fuel proceeds netted with capital expenditures represents less than 2%, 5%, 6% and 3% of the net cash used in investing activities for the year ended December 31, 2014, for Duke Energy Corporation, Progress Energy, Inc., Duke Energy Progress, Inc. and Duke Energy Florida, Inc., respectively.

Combined Notes to Consolidated Financial Statements

4. Regulatory Matters, page 132

8. We noted a significant increase in your regulatory asset related to asset retirement obligations during the fiscal year ended December 31, 2014, which appears to be the portion of the asset retirement obligations recorded during the current year that are attributable to retired plants, consistent with your disclosure on page 118. Please confirm our assumption or tell us in detail what these deferred costs represent. We also note your disclosure on page 146 that the Coal Ash Act leaves the decision on cost recovery determinations related to closure of coal combustion residuals surface impoundments to the normal ratemaking processes before utility regulatory commissions and your disclosure on page 162 that you believe recovery is probable. We further note your disclosure in multiple instances, such as on page 41, that an order from the regulatory authorities disallowing recovery of costs related to closure of ash basins could have an adverse impact on your financial statements. As it appears you do not have a regulatory order supporting the deferral of these costs, please tell us why you believe the amounts you have deferred as regulatory assets are probable of recovery under U.S. GAAP and provide us with your detailed analysis supporting this conclusion including both positive and negative evidence you considered. Refer to ASC 980-340-25-1.

Both the North Carolina Utility Commission (the NCUC) and the South Carolina Public Service Commission (the SCPSC) issued Accounting Orders in 2003 to Duke Energy Carolinas and Duke Energy Progress requiring the deferral of the income statement impacts of accounting for asset retirement obligations required by ASC 410, for both the initial adoption and prospective impacts. Prior to ASC 410, NCUC and SCPSC would set retail rates to recover asset retirement costs as a cost of removal of an asset generally over the life of the asset. The intent of this deferral order was to allow this historical rate recovery practice to continue and that the recognition and measurement of asset retirement obligations under ASC 410 would have no current impact on retail rates. This regulatory accounting practice is common in the industry and continues to be followed in the North Carolina and South Carolina retail jurisdictions and has been applied to Duke Energy Carolinas and Duke Energy Progress asset retirement obligations, including those resulting from CAMA.

CAMA introduced new costs related to coal ash basin closure obligations that previously would not have been considered in setting rates and therefore would not have been collected over the years of service of Duke Energy Carolinas and Duke Energy Progress operating or retired plants. It is not uncommon in the industry to experience regulatory rate lag whereby emerging costs have not yet been fully considered in setting rates charged to customers, thereby delaying recovery of these costs. The increase in regulatory assets associated with asset retirement costs is primarily attributable to asset retirement costs to retire ash basins at our retired plants as discussed more fully in Note 9, Asset Retirement Costs, Ash Basins, Page 162.

Establishing a regulatory asset absent a definitive rate action requires considerable judgment and analysis to support recognition and measurement of regulatory assets in financial statements. ASC 980-340-25-1 states the following:

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 6

“Rate actions of a regulator can provide reasonable assurance of the existence of an asset. An entity shall capitalize all or part of an incurred cost that would otherwise be charged to expense if:

a.  It is probable (as defined in Topic 450) that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate-making purposes; and

b.  Based on available evidence, the future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs. If the revenue will be provided through an automatic rate-adjustment clause, this criterion requires that the regulator's intent clearly be to permit recovery of the previously incurred cost.”

We believe that “rate actions of a regulator” includes both current and historic practices and precedent of a regulator. PriceWaterhouseCoopers has published guidance in its “Guide to Accounting for Utilities and Power Companies” 2013 edition, Section 17.3.1.2, Recovery of Incurred Costs is Probable, outlining examples of the forms of evidence to support the recognition of regulatory asset. Although the examples below are not numbered in the published guidance, we have included such to provide a reference to other points within this document:

i. "The regulated utility receives a rate order specifying that the costs will be recovered in the future.

ii. The incurred cost has been treated by the regulated utility’s regulator as an allowable cost of service item in prior regulatory filings.

iii. The incurred cost has been treated as an allowable cost by the same regulator in connection with another entity’s filing.

iv. It is the regulator’s general policy to allow recovery of the incurred cost.

v. The regulated utility has had discussions with the regulator (as well as its primary intervener groups) with respect to recovery of the specific incurred cost and has received assurances that the incurred cost will be treated as an allowable cost (and not challenged) for regulatory purposes.

vi. The specific incurred cost (or similar incurred cost) has been treated as an allowable cost by a majority of other regulators and has not been specifically disallowed by the regulated utility’s regulator.

vii. The regulated utility has obtained an opinion from outside legal counsel outlining the basis for the incurred cost being probable of being allowed in future rates.

Different forms of evidence will provide varying degrees of support for management’s assertion that a regulatory asset is probable of recovery; not all forms of evidence will be sufficient in isolation or in combination to make such an assertion.

Establishing probability of recovery is more difficult absent a rate order, especially when evaluating unusual or nonrecurring costs.

Prior to concluding that recognition of a regulatory asset is appropriate, a regulated utility should also consider other relevant factors, such as:

viii. The regulatory principles and precedents established by law

ix. The political and regulatory environment of the jurisdiction (e.g., does further regulation occur in the courts)

x. The magnitude of the incurred costs to be deferred and the related impact on ratepayers if such costs are allowed (taking into account the length of the recovery period)

xi. Whether ratepayers or others may intervene in an attempt to deny recovery.”

All of these criteria were considered contemporaneously with the recognition of the Asset Retirement Obligation (ARO) related to the enactment of CAMA in North Carolina in 2014 and are addressed individually in this response.

First we addressed the consideration of two of these recommendations. Number references are previously assigned within this document and the considerations are intentionally not addressed below in numerical order:

i. The regulated utility receives a rate order specifying that the costs will be recovered in the future.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 7

v. The regulated utility has had discussions with the regulator (as well as its primary intervener groups) with respect to recovery of the specific incurred cost and has received assurances that the incurred cost will be treated as an allowable cost (and not challenged) for regulatory purposes.

The Act contains a moratorium on seeking rate recovery related to compliance costs of the Act until January 15, 2015. The purpose of this provision in the Act was in part to allow for full consideration by the Commissions of the potential impacts of the pending U.S. Environmental Protection Agency's action over coal combustion residuals (CCR), before any rate action was taken to address recovery of the ash basin closure costs. CCR requirements were expected at the time of enactment of the Act to be issued later in 2014 and were officially enacted in the second quarter of 2015.

The Company continues to evaluate the full impacts of the Act and the newly enacted CCR requirements as it formulates compliance plans prior to approaching the applicable commissions for definitive rate action. Therefore at the time of the recognition of the initial ARO in the third quarter of 2014 and at year end, no discussions with these regulatory authorities had taken place.

What follows is the analysis and conclusions of additional considerations we made in support of the regulatory asset for ash basin retirement costs:

ii. The incurred cost has been treated by the regulated utility’s regulator as an allowable cost of service item in prior regulatory filings.

The specific incurred cost, ash basin closure costs, has been treated by the NCUC in the past as an allowable cost of service in prior regulatory rate filings. Duke Energy Progress has estimated future amounts related to the closure of ash basins under an approach that was an accepted industry practice (cap in place) prior to the passage of CAMA. Although these amounts are not at the scale and level of compliance costs necessary to comply with the Act, the cost recovery was approved by the NCUC.

A similar request has not been made before SCPSC, but in general, rate setting practices are similar in both North Carolina and South Carolina jurisdictions (see also retail recovery legal opinion discussion below).

For Federal Energy Regulatory Commission (FERC) purposes, Duke Energy Progress ash basin closure costs under the same cap in place compliance approach as provided for in the Duke Energy Progress North Carolina base rate case have been reflected in wholesale cost of service to date (see further discussion on wholesale recovery below).

iii. The incurred cost has been treated as an allowable cost by the same regulator in connection with another entity’s filing.

Based on our research we are not aware of any other utilities regulated by the NCUC or the SCPSC having been allowed (or denied) to treat retirement costs of coal ash basins as an allowable cost within a rate case filing.

iv. It is the regulator’s general policy to allow recovery of the incurred cost.

NCUC and SCPSC as well as the FERC have previously allowed recovery of incurred costs for other asset retirement obligations. Currently Duke Energy Carolinas and Duke Energy Progress have asset retirement costs reflected in rates for actual incurred costs or expected costs to be incurred for the following types of asset retirement obligations:

• Nuclear decommissioning

• Landfills

• Asbestos removal

• Regulated solar panels

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 8

Duke Energy Carolinas and Duke Energy Progress have historically received favorable cost recovery treatment for the several types of environmental compliance costs from the NCUC, SCPSC and FERC, including:

• Clean smokestacks legislation in North Carolina

• Air quality control equipment including scrubbers, precipitators and flue gas desulfurization equipment

• Mercury monitoring equipment

• Groundwater monitoring equipment

More generally, under the regulations and rulings of the NCUC, SCPSC and FERC, utilities have the right and have historically recovered prudently incurred costs of owning and operating facilities that are used and useful, including both operating and retired facilities.

Please note item "v." was previously addressed.

vi. The specific incurred cost (or similar incurred cost) has been treated as an allowable cost by a majority of other regulators and has not been specifically disallowed by the regulated utility’s regulator.

The historical practice of recovery of similar or specific incurred ash basin closure costs by regulators in general was addressed as part of legal counsel evaluations discussed below.

vii. The regulated utility has obtained an opinion from outside legal counsel outlining the basis for the incurred cost being probable of being allowed in future rates.

The Company's in-house lead counsel responsible for the most recent base rate cases in the Carolinas prepared an evaluation of the probability of recovery of ash basin closure costs from retail customers related to the Act. The legal opinion from in-house counsel detailed the conclusions from previous rate orders and commission actions and concluded that ash basin closure costs are probable of recovery.

As it relates to recovery of ash basin closure costs from wholesale customers related to the Act, the Company (i) performed a detailed review of all existing wholesale contracts to determine if stated contract rates can be changed to provide recovery of ash basin closure costs and (ii) obtained legal opinions from in-house and external legal counsel. The results of this contract review and these legal opinions supported the conclusion that ash basin closure costs are probable of recovery.

Other Considerations

viii. The regulatory principles and precedents established by law

These were addressed as part of the legal opinions and analysis provided by legal counsel.

ix. The political and regulatory environment of the jurisdiction (e.g., does further regulation occur in the courts)

The political and regulatory environment in North Carolina has elevated the visibility and awareness over the costs associated with the closure of these ash basins. While the legislation contained in the Act contained prohibitions related to costs recovery of certain environmental compliance costs associated with noncompliance at the ash basins (i.e., spills), it does not contain such restrictions for the closure costs of the ash basins. The Act leaves cost recovery authority to the commissions regarding recovery of ash basin closure costs.

x. The magnitude of the incurred costs to be deferred and the related impact on ratepayers if such costs are allowed (taking into account the length of the recovery period)

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 9

The magnitude of the incurred costs to be deferred and the related impact on customers taking into account a recovery period equal in length to the period over which costs are expected to be incurred to meet ash removal compliance deadlines within the Act (over a 15-year period) are not expected to be material to total customer bills. The expected impacts on retail customer bills would range from 2 percent to 3 percent (2 percent to 2.5 percent for Duke Energy Carolinas and 2.5 percent to 3 percent for Duke Energy Progress). The expected impact on wholesale customer bills are on average 2 percent and 3 percent at Duke Energy Carolinas and Duke Energy Progress, respectively, above current rates.

xi. Whether ratepayers or others may intervene in an attempt to deny recovery

Although intervention in any requested rate action is to be expected from customers or other interests, the Company firmly believes and expects that the respective state and federal commissions will follow customary rate setting process and historic precedents in allowing recovery.

Based on this analysis and consideration of evidence, both positive (e.g., the historic recovery in the Company's retail jurisdictions of ash basin closure costs and similar asset retirement costs) and negative (e.g., the historic recovery of ash basin closure costs in the Company's retail jurisdiction has not been at the scale and level of compliance costs necessary to comply with CAMA), the Company concluded that both the retail and wholesale portions of deferred ash basin closure costs were probable of recovery as of December 31, 2014, and met the requirements of ASC 980-340-25-1.

Duke Energy Progress

Shearon Harris Nuclear Station Expansion, page 137

9. Please tell us in detail why you believe recovery of the $48 million regulatory asset related to the Shearon Harris Nuclear Station Expansion is probable as of December 31, 2014. Please contrast the nature of these costs with that of the $22 million impairment you recorded during the fiscal year ended December 31, 2013 for costs you deemed were not probable of recovery. Refer to ASC 980-340-25-1.

In May 2013, Duke Energy Progress announced its intention to indefinitely suspend efforts related to the potential for new nuclear units at Shearon Harris Nuclear Station (Harris). This decision resulted in separate assessments of the probability for recovery of the retail and wholesale portions of the investment in Harris development costs. First, in determining retail recovery the Company discussed the matter with the Public Staff for North Carolina and the Office of Regulatory Staff for South Carolina, and filed petitions with the appropriate commissions for an accounting order for regulatory deferral of the retail costs. Regulatory approval for deferral and future rate treatment of these costs was subsequently received from both the NCUC and SCPSC. Based on this recoverability and rate treatment of the retail portion of these costs, the Company concluded that recovery of the $48 million regulatory asset is probable and meets the requirements of ASC 980-340-25-1.

By contrast, for wholesale cost recovery, the $22 million impairment recorded during the fiscal year ended December 31, 2013, was determined to be unrecoverable based on long-standing precedent and historic FERC rate treatment and limitations on recovery in Duke Energy Progress' wholesale contracts. A portion of this impairment was also attributed to unrecovered carrying costs on the retail regulatory asset.

11. Goodwill and Intangible Assets

Intangible Assets, page 167

10. We note your disclosure on pages 167 and 205 related to the $94 million OVEC impairment charge. Please tell us more about the facts and circumstances related to OVEC that existed as of December 31, 2013 as compared to December 31, 2014, what led to the impairment, and how you complied with the non-recurring fair value measurement disclosures related to this impairment required by ASC 820-10-50.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 10

At December 31, 2013, Duke Energy had not made a decision to exit the nonregulated Midwest generation business, including its contractual interest in the power purchase agreement with OVEC, as it was waiting for a decision from the Public Utilities Commission of Ohio (PUCO) on its request for additional revenues through a capacity rate rider for the provision of capacity services in Ohio. On February 13, 2014, the PUCO denied Duke Energy Ohio's requests in the Capacity Rider Filing. On February 14, 2014, management requested and the Board of Directors of Duke Energy approved the initiation of the process to sell the nonregulated Midwest generation business and the Company contacted and engaged financial advisers on the transaction. On February 17, 2014, Duke Energy announced it had initiated a strategic process to exit its Midwest generation business, and this asset group included the contractual interest in the power purchase agreement with OVEC.

Accordingly, as of December 31, 2013, the intangible asset associated with Duke Energy Ohio’s contractual interest with OVEC was accounted for as held and used. ASC 350-30-35-14 states that an intangible asset that is subject to amortization shall be reviewed for impairment in accordance with the Impairment of Long-Lived Assets Subsections of ASC 360-10. Under ASC 360-10, long-lived assets (asset groups) classified as held and used shall be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The Company considered whether any events or change in circumstances triggered a recoverability test under ASC 360 during each quarter during 2013 and did not identify any triggering events requiring an impairment test during 2013. Duke Energy concluded there were no events or changes in circumstances noted in 2013 that indicated the OVEC intangible had a carrying value that was not recoverable, and at no point in 2013 did Duke Energy assess that it was more likely than not the contractual entitlements with OVEC would be sold or otherwise disposed of significantly before the end of the estimated contract term of 26 years.

In the first quarter of 2014, the nonregulated Midwest generation disposal group included the contract with OVEC and qualified as assets held for sale and accordingly was fair valued as part of the disposal group. In the second quarter of 2014, the Company removed the contractual interest in OVEC from the disposal group as the potential buyers that submitted indicative bids did not express interest in the OVEC contract and none of the parties met the credit quality standards required to assume the contract. Management decided to include the power agreement with OVEC in Duke Energy Ohio’s 2014 Electric Security Plan (ESP) filing in May 2014, requesting a cost-based recovery treatment similar to the treatment American Electric Power, a joint owner in OVEC, was also seeking in its pending ESP filing before the PUCO.

In accordance with ASC 360-10-35-44, as a result of the change in plan to sell OVEC, the intangible asset associated with OVEC was removed from the disposal group and reclassified as held and used. ASC 360-10-35-44 states that when an asset is reclassified from held for sale to held and used, it should be reclassified at the lower of (1) its carrying amount before the investment was classified as held for sale, adjusted for amortization or (2) its fair value at the date of the subsequent decision not to sell. Based on valuation work done to support the fair value of the nonregulated Midwest generation disposal group under the held for sale classification and the decision to seek a cost-based recovery mechanism (but with no return on the intangible carrying value) for the contract with OVEC in Duke Energy Ohio’s ESP filed in May 2014, a $94 million impairment was recorded to eliminate the full carrying value the intangible asset had prior to being classified as held for sale.

The Company believes the footnotes adequately address the non-recurring fair value measurement disclosures required under ASC 820-10-50, by disclosing that Duke Energy requested a cost-based recovery of its contractual entitlement in OVEC in its ESP (see Footnote 2, Acquisitions, Dispositions and Sales of Other Assets on page 125) and the economic influences impacting the contract value (see Footnote 17, Variable Interest Entities on page 205).

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 11

22. Income Taxes, page 227

11. Your declaration of a taxable dividend of the cumulative historical undistributed earnings of your foreign subsidiaries during the fiscal year ended December 31, 2014 is a change in your assertion from the prior fiscal year that the undistributed foreign earnings associated with International Energy’s operations were considered indefinitely reinvested. As disclosed on page 62 of your Form 10-K for the fiscal year ended December 31, 2013, this assertion was based on your determination that the cash held in International Energy’s foreign jurisdictions was not needed to fund the operations of U.S. operations and that International Energy either had invested or had intentions to reinvest such earnings. We note your disclosure on page 59 that this dividend will be principally used to support your dividend and growth in the domestic business. We also note your disclosure on page 229 that your current intention is to indefinitely reinvest prospective undistributed earnings generated by your foreign subsidiaries and, therefore, you will not provide for U.S. taxes on those earnings. In light of your decision to repatriate your cumulative historical undistributed foreign earnings and in order to overcome the presumption that all undistributed earnings will be transferred to the parent entity, please tell us in detail what evidence you have of specific plans for reinvestment of undistributed earnings of your foreign subsidiaries which demonstrates that remittance of future earnings will be postponed indefinitely. Refer to ASC 740-30-25-3 and -17.

We acknowledge that ASC 740-30-25-3 states that it "shall be presumed that all undistributed earnings of a subsidiary will be transferred to the parent entity” and ASC 740-30-25-17 states that this presumption "may be overcome, and no income taxes shall be accrued by the parent entity ... if sufficient evidence shows that the subsidiary has invested or will invest the undistributed earnings indefinitely." The criteria required to overcome the presumption are sometimes referred to as the indefinite reversal criteria. Given the decision to repatriate our historical undistributed earnings, we reviewed in detail the factors resulting in the declaration of a taxable dividend, future operating and finance plans, budgets and forecasts to determine whether future forecasted undistributed earnings would be considered indefinitely reinvested.

The decision to repatriate historical earnings in 2014 from our foreign operations was not due to an adverse event impacting the Company’s overall liquidity position, especially given the near-term realization of $2.8 billion in proceeds from the sale of Midwest generation assets and our overall liquidity position as disclosed in the 2014 Form 10-K MD&A (pages 58-60). This is further supported by the structure to dividend historical unremitted offshore earnings to the parent company, executed in the form of three interest bearing notes totaling $2.7 billion, with maturities ranging from one yearto eight years. Rather, the timing of the repatriation was attributed largely to unique tax attributes of the Company’s domestic operations in 2014 that allowed the return of these funds in a tax-efficient manner.

Based on International Energy's current operating plans, its discrete cash flow forecast for the next five years (2015- 2019) assumes that after considering operating free cash flow, total capital expenditures and debt service obligations over this time period (including those associated with the $2.7 billion notes), the net cash flows are expected to be negative, reducing available cash by over $700 million. No repatriation of International Energy earnings is assumed in this plan beyond the 2014 dividend. The remaining available cash balance will provide International Energy with operational and investment flexibility, including the expectation for International Energy to pursue opportunities in emerging and growing energy markets in the foreign countries in which it operates.

Based on these considerations, there is sufficient evidence to support management's assertion that it has the ability and intent to indefinitely reinvest prospective earnings beyond the 2014 dividend.

Jennifer Thompson

U.S. Securities Exchange Commission

June 26, 2015

Page 12

Duke Energy acknowledges:

• it is responsible for the adequacy and accuracy of the disclosure in the filing;

• Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please do not hesitate to call me at 704 382.6242 with any questions regarding the foregoing.

Very truly yours,

/s/ Brian D. Savoy    

Brian D. Savoy

Senior Vice President, Chief Accounting Officer and Controller

Cc:    Lynn J. Good, Vice Chairman, President and Chief Executive Officer

Steven K. Young, Executive Vice President and Chief Financial Officer

Julia S. Janson, Executive Vice President, Chief Legal Officer and Corporate Secretary