USFE&G supplies electric service to 7.2 million residential, general service and industrial customers. Its service area covers approximately 104,000 square miles with an estimated population of 22 million. USFE&G provides regulated transmission and distribution services for natural gas to 500,000 customers in southwestern Ohio and northern Kentucky. Electricity is also sold wholesale to incorporated municipalities, electric cooperative utilities and other load serving entities.

Duke Energy Carolinas’ and Progress Energy Carolinas’ service areas share a diversified economy that is driven by service, manufacturing and government related output and jobs. Sales to general service customers, which include both service and government sectors, represent approximately one third of total retail sales and the main segments include health care, education, financial services, information technology and military buildings. Sales to industrial customers represent a little less than one third of total retail sales and key sectors are textiles, chemicals, rubber and plastics, paper, food & beverage and auto manufacturing.

Progress Energy Florida’s service area has a strong base of residential customers and lower percentages of general service and industrial customers relative to the other Duke Energy utilities’ states. Sales to general service customers, which include both service and government sectors, represent approximately 40% of total retail sales; the largest service segments include tourism, heath care and agriculture. Sales to industrial customers represent only around 10% of total retail sales and main sectors include phosphate rock mining and processing, electronics design and manufacturing, and citrus and other food processing.

Duke Energy Indiana’s service area is characterized by a strong presence of manufacturing activity. Sales to industrial customers represent around 40% of total retail volumes; the larger segments within the industrial class include primary metals, transportation equipment, building materials, food & beverage and chemicals. Sales to general service customers represent approximately 30% of total retail and the largest contributors to general service sales include retail, financial, health care and education services.

Duke Energy Ohio’s service area has a diversified economy that is driven by primarily by the services sector. The contribution of manufacturing to the regional economy is lower relative to Indiana and the Carolinas’ service territories. Sales to general service customers, which include both service and government sectors, represent approximately 40% of total retail sales and the main segments include healthcare, education, real estate and rental leasing, financial & insurance services and wholesale trade services. Sales to industrial customers represent approximately one fourth of total retail sales and key industries are aerospace, primary metals, chemicals and food.

The number of residential, general service and industrial customers within the USFE&G service territory, as well as sales to these customers, is expected to increase over time. However, growth in the near-term is being hampered by the current economic conditions. While total industrial sales increased in 2012 when compared to 2011, the growth rate was modest when compared to historical periods.

USFE&G’s costs and revenues are influenced by seasonal patterns. Peak sales of electricity occur during the summer and winter months, resulting in higher revenue and cash flows during those periods. By contrast, fewer sales of electricity occur during the spring and fall, allowing for scheduled plant maintenance during those periods. Peak gas sales occur during the winter months. Residential and general service customers are most impacted by weather. Industrial customers are less weather sensitive. Estimated weather impacts are based on actual current period weather compared to normal weather conditions, with normal weather conditions defined as the long-term average of actual historical weather conditions.

The estimated impact of weather on earnings is based on the number of customers, temperature variances from a normal condition and customers’ historic usage levels and patterns. The methodology used to estimate the impact of weather does not and cannot consider all variables that may impact customer response to weather conditions such as humidity and relative temperature changes. The precision of this estimate may also be impacted by applying long-term weather trends to shorter term periods.

Degree-day data are used to estimate the energy required to maintain comfortable indoor temperatures based on each day’s average temperature. Heating-degree days measure the variation in the weather based on the extent to which the average daily temperature falls below a base temperature, and cooling-degree days measure the variation in weather based on the extent to which the average daily temperature rises above the base temperature. Each degree of temperature below the base temperature counts as one heating-degree day and each degree of temperature above the base temperature counts as one cooling-degree day.

Retail. USFE&G’s regulated utility businesses operate as the sole supplier of electricity within their service territories. USFE&G owns and operates all of the businesses and facilities necessary to generate, transmit and distribute electricity. Services are priced by state commission approved rates designed to include the costs of providing these services and a reasonable return on invested capital. This regulatory policy is intended to provide safe and reliable electricity at fair prices. USFE&G’s competition in the regulated electric distribution business is primarily from the on-site generation of industrial customers.

USFE&G is not aware of any enacted or proposed legislation in North Carolina, South Carolina, Florida, Kentucky or Indiana that would give its retail customers the right to choose their electricity provider or otherwise restructure or deregulate the electric industry. However, USFE&G competes with suppliers of other forms of energy in connection with their retail customers.

Although there is no pending legislation at this time, if the retail jurisdictions served by USFE&G become subject to deregulation, the recovery of “stranded costs” could become a significant consideration. Stranded costs primarily include the generation assets of USFE&G’s regulated utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to qualified facilities (QFs). QFs are typically small power production facilities that generate power within a utility company’s service territory for which the utility companies are legally obligated to purchase the energy of these facilities at an avoided cost rate. Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs.

USFE&G’s largest stranded cost exposure is primarily related to Progress Energy Florida’s purchased power commitments with QFs, under which it has future minimum expected capacity payments through 2025 of $3.8 billion. Progress Energy Florida was obligated to enter into these contracts under provisions of the Public Utilities Regulatory Policies Act of 1978. Progress Energy Florida continues to seek ways to address the impact of escalating payments under these contracts. However, the FPSC allows full recovery of the retail portion of the cost of power purchased from QFs. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies” for additional information related these purchased power commitments.

Wholesale. USFE&G competes with other utilities and merchant generators for bulk power sales and for sales to municipalities and cooperatives. USFE&G also competes with other utilities and marketers in the wholesale electric business. The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service. Wholesale electric prices are influenced primarily by market conditions and fuel costs.

Increased competition in the wholesale electric utility industry and the availability of transmission access could affect USFE&G’s load forecasts, plans for power supply and wholesale energy sales and related revenues. Wholesale energy sales will be impacted by the extent to which additional generation is available to sell to the wholesale market and the ability of USFE&G to attract new wholesale customers and to retain current wholesale customers.

USFE&G owns over 50,000 megawatts of generation capacity. For additional information on USFE&G’s generation facilities, see “U.S. Franchised Electric and Gas” in Item 2.“Properties.”

Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Factors that could cause USFE&G to purchase power for its customers include generating plant outages, extreme weather conditions, generation reliability during the summer, growth, and price. USFE&G has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, sale and purchase of capacity and energy, and reliability of power supply.

USFE&G’s generation portfolio is a balanced mix of energy resources having different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet its obligation to serve native-load customers. All options, including owned generation resources and purchased power opportunities, are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements.

The vast majority of Duke Energy Carolinas, Progress Energy Carolinas, and Duke Energy Indiana’s customer energy needs have historically been met by large, low-energy-production-cost coal-fired and nuclear generating units that operated almost continuously (or at baseload levels). However, recent commodity pricing trends have resulted in more combined cycle gas-fired generation. The vast majority of Progress Energy Florida’s customer energy needs have historically been met by large, low-energy-production-cost nuclear, fossil steam and combined cycle gas-fired generation. However, due to the extended outage of the Crystal River Nuclear Station Unit 3 (Crystal River Unit 3) nuclear plant a portion of customer needs have been served with purchased power for the past 3 years.

CT’s and CC’s are less expensive to build and maintain than either nuclear or coal, and can be rapidly started or stopped as needed to meet changing customer loads or operated as base load units depending on commodity prices. Hydroelectric units produce low-cost energy, but their operations are limited by the availability of water flow.

USFE&G’s pumped-storage hydroelectric facilities in the Carolinas offer the added flexibility of using low-cost off-peak energy to pump water that will be stored for later generation use during times of higher-cost on-peak periods. These facilities allow USFE&G to maximize the value spreads between different high- and low-cost generation periods.

Recently Completed Generation Projects. During 2012 and 2011, USFE&G completed construction of and placed into service a total of 3,585 megawatts (MW) of new generation capacity including Cliffside Unit 6 and the Buck, Dan River, Lee and Smith combined cycle natural gas facilities. The total capital cost of this new generation capacity was $4.8 billion.

Generation Projects Currently Under Construction. The following information relates to generation projects currently under construction by USFE&G.

Edwardsport Integrated Gasification Combined Cycle (IGCC)Plant. Duke Energy Indiana has completed the construction and is conducting testing of a 618 MW Integrated Gasification Combined Cycle (IGCC) power plant at its existing Edwardsport Generating Station in Knox County, Indiana.

On December 27, 2012, the IURC approved the settlement agreement finalized in April 2012  between Duke Energy Indiana, the Office of Utility Consumer Counselor (OUCC), the Duke Energy Indiana Industrial Group and Nucor Steel Indiana, on the cost increase for the construction of the Edwardsport IGCC plant. The settlement agreement, as approved, caps costs to be reflected in customer rates at $2.595 billion, including estimated allowance for funds used during construction (AFUDC) through June 30, 2012. Duke Energy Indiana was allowed to recover AFUDC after June 30, 2012 until customer rates are revised, with such recovery decreasing to 85% on AFUDC accrued after November 30, 2012.

Duke Energy Indiana’s current cost estimate for the Edwardsport IGCC plant is approximately $3.154 billion, excluding financing costs. Through December 31, 2012, Duke Energy Indiana has recorded total pre-tax impairment and other charges of $897 million related to the Edwardsport IGCC plant. If cost estimates for the plant increase, additional charges to expense, which could be material, could occur. The Edwardsport IGCC plant is expected to be in service by mid-2013. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters” for further information.

L.V. Sutton Combined Cycle Facility. Progress Energy Carolinas is in the process of constructing an approximately 625 MW natural gas-fired generating facility at its existing L.V. Sutton Steam Station (Sutton) in New Hanover County, North Carolina. The Sutton project has an expected in-service date of December 2013. Based on updated cost estimates, total costs (including AFUDC) for the Sutton project is estimated to be approximately $600 million.

Potential New Construction. The following information relates to major generation projects currently being evaluated for construction by USFE&G.

Shearon Harris Nuclear Station Expansion. In 2006, Progress Energy Carolinas selected a site at its existing Shearon Harris Nuclear Station (Harris) to evaluate for possible future nuclear expansion. On February 19, 2008, Progress Energy Carolinas filed its combined Construction and Operating License (COL) application with the Nuclear Regulatory Commission (NRC) for two Westinghouse Electric Advanced Passive (AP) 1000 reactors at Harris, which the NRC docketed on April 17, 2008. No petitions to intervene have been admitted in the Harris COL application.

Levy Nuclear Station. On July 30, 2008, Progress Energy Florida filed its COL application with the NRC for two Westinghouse AP1000 reactors at its proposed Levy Nuclear Station (Levy), which the NRC docketed on October 6, 2008. Various parties filed a joint petition to intervene in the Levy COL application. On October 31, 2012 and November 1, 2012, the Atomic Safety and Licensing Board held an evidentiary hearing on portions of the intervention petitions.  A decision is expected in March 2013. In 2008, the FPSC granted Progress Energy Florida’s petition for an affirmative Determination of Need and related orders requesting cost recovery under Florida’s nuclear cost-recovery rule for Levy, together with the associated facilities, including transmission lines and substation facilities.

On April 30, 2012, as part of its annual nuclear cost recovery filing, Progress Energy Florida updated the Levy project schedule and cost. Due to lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current low natural gas prices, Progress Energy Florida has shifted the in-service date for the first Levy unit to 2024, with the second unit following 18 months later. The revised schedule is consistent with the recovery approach included in the 2012 FPSC Settlement Agreement. Although the scope and overnight cost for Levy, including land acquisition, related transmission work and other required investments, remain essentially unchanged, the shift in schedule will increase escalation and carrying costs and raise the total estimated project cost to between $19 billion and $24 billion.

Along with the FPSC’s annual prudence reviews, Progress Energy Florida will continue to evaluate the project on an ongoing basis based on certain criteria, including, but not limited to, cost; potential carbon regulation; fossil fuel prices; the benefits of fuel diversification; public, regulatory and political support; adequate financial cost-recovery mechanisms; appropriate levels of joint owner participation; customer rate impacts; project feasibility; demand side management (DSM) and energy efficiency (EE) programs; and availability and terms of capital financing. Taking into account these criteria, Levy is considered to be Progress Energy Florida’s preferred baseload generation option.

Under the terms of the 2012 FSPC Settlement Agreement, Progress Energy Florida began residential cost-recovery of its proposed Levy Nuclear Station effective in the first billing cycle of January 2013 at the fixed rates contained in the settlement and continuing for a five-year period, with true-up of any actual costs not recovered during the five year period occurring in the final year. Progress Energy Florida will not file for recovery of any new Levy costs that were not addressed in the 2012 FSPC Settlement Agreement before March 1, 2017 and will not begin recovering those costs from customers before the first billing cycle of January, 2018, unless otherwise agreed to by the parties to the agreement. This amount is intended to recover the estimated retail project costs to date plus costs necessary to obtain the COL and any engineering, procurement and construction cancellation costs, if Progress Energy Florida ultimately chooses to cancel that contract. In addition, the consumer parties will not oppose Progress Energy Florida continuing to pursue a COL for Levy. The 2012 FSPC Settlement Agreement also provides that Progress Energy Florida will treat the allocated wholesale cost of Levy (approximately $68 million) as a retail regulatory asset and include this asset as a component of rate base and amortization expense for regulatory reporting. Progress Energy Florida will have the discretion to accelerate and/or suspend such amortization in full or in part provided that it amortizes all of the regulatory asset by December 31, 2016.

William States Lee III Nuclear Station. In December 2007, Duke Energy Carolinas filed an application with the NRC, which has been docketed for review, for a combined COL for two Westinghouse AP1000 reactors for the proposed William States Lee III Nuclear Station (Lee Nuclear Station) at a site in Cherokee County, South Carolina. Each reactor is capable of producing 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. Through several separate orders, the NCUC and PSCSC have concurred with the prudency of Duke Energy incurring project development and pre-construction costs.

Potential 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 (15-20 years), and options being considered to meet those needs. The IRP’s filed by the Subsidiary Registrants in 2012 and 2011 included planning assumptions to potentially retire by 2015, certain coal-fired generating facilities in North Carolina, South Carolina, Indiana and Ohio that do not have the requisite emission control equipment, primarily to meet Environmental Protection Agency (EPA) regulations that are not yet effective. Additionally, management is considering the impact pending environmental regulations might have on certain coal-fired generating facilities in Florida. These facilities total approximately 3,954 MW at eight sites. Duke Energy continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery for amounts that would not be otherwise recovered when any assets are retired. For additional information related to potential plant retirements see Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”

The current average sulfur content of coal purchased by USFE&G is between 1% and 2% for the Carolinas; between 1% and 2% for Florida, and between 2% and 3% for Indiana. USFE&G’s scrubbers, in combination with the use of sulfur dioxide (SO ₂ ) emission allowances, enable USFE&G to satisfy current SO ₂ emission limitations for its existing facilities.

Nuclear. The industrial processes for producing nuclear generating fuel generally involve the mining and milling of uranium ore to produce uranium concentrates, the services to convert uranium concentrates to uranium hexafluoride, the services to enrich the uranium hexafluoride, and the services to fabricate the enriched uranium hexafluoride into usable fuel assemblies.

USFE&G has contracted for uranium materials and services to fuel its nuclear reactors in the Carolinas and Florida. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. USFE&G staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements in the near-term and decreasing portions of its fuel requirements over time thereafter. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with spot market purchases. Due to the technical complexities of changing suppliers of fuel fabrication services, USFE&G generally sources these services to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

USFE&G has entered into fuel contracts that, based on its current need projections, cover 100% of its uranium concentrates, conversion services, and enrichment services requirements through at least 2013 and cover fabrication services requirements for these plants through at least 2018. The cost of termination of nuclear fuel procurement contracts that Progress Energy Florida has related to Crystal River Unit 3 are not expected to be material. For subsequent years, a portion of its fuel requirements are covered by long-term contracts. For future requirements not already covered under long-term contracts, USFE&G believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services.

Gas. Oil and natural gas supply for USFE&G’s generation fleet is purchased under term and spot contracts from various suppliers. Duke Energy Carolinas and Progress Energy Carolina’s use derivative instruments to limit their exposure to price fluctuations for natural gas. Progress Energy Florida uses derivative instruments to limit its exposure to price fluctuations for natural gas, fuel oil and surcharges embedded in coal transportation agreements. USFE&G has dual-fuel generating facilities that can operate with both fuel oil and natural gas. The cost of USFE&G’s oil and natural gas is either at a fixed price or determined by market prices as reported in certain industry publications. USFE&G believes that it has access to an adequate supply of oil and gas for the reasonably foreseeable future. USFE&G’s natural gas transportation for its gas generation is purchased under term firm transportation contracts with interstate and intrastate pipelines. USFE&G may also purchase additional shorter-term transportation for its load requirements during peak periods. Many of the natural gas plants can be served by several supply zones and multiple pipelines.

Purchased Power. USFE&G purchased approximately 19.8 million MWh, 19.0 million MWh and 18.3 million MWh of its system energy requirements during 2012, 2011, and 2010, respectively, under purchase obligations and leases and had 4,500 MW of firm purchased capacity under contract during 2012. These amounts include MWh for Progress Energy Carolinas and Progress Energy Florida for all periods presented. These agreements include approximately 682 MW of firm capacity under contract by Progress Energy Florida with certain QFs. USFE&G may need to acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. USFE&G believes that it can obtain adequate purchased power to meet these needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected.

Gas for Retail Distribution. USFE&G is responsible for the purchase and the subsequent delivery of natural gas to native load customers in its Ohio and Kentucky service territories. USFE&G’s natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows USFE&G to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides USFE&G the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under USFE&G customer choice/gas transportation programs. In 2012, firm supply purchase commitment agreements provided approximately 100% of the natural gas supply. These firm supply agreements feature two levels of gas supply, specifically (i) base load, which is a continuous supply to meet normal demand requirements, and (ii) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.

USFE&G also owns two underground caverns with a total storage capacity of 16 million gallons of liquid propane. In addition, USFE&G has access to 5.5 million gallons of liquid propane storage and product loan through a commercial services agreement with a third party. This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants vaporize the propane and mix it with natural gas to supplement the natural gas supply during peak demand periods.

Duke Energy Ohio maintains natural gas procurement-price volatility mitigation programs. These programs pre-arrange percentages of Duke Energy Ohio’s seasonal gas requirements. Duke Energy Ohio uses primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2012, Duke Energy Ohio had locked in pricing for 22% of its remaining estimated winter 2012/2013 system load requirements.

Generation of electricity is capital-intensive. USFE&G must maintain an adequate stock of fuel, materials and supplies in order to ensure continuous operation of generating facilities and reliable delivery to customers. As of December 31, 2012, the inventory balance for USFE&G was $2,987 million. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

USFE&G owns (wholly or partially) 12 nuclear reactors located at seven stations. Nuclear insurance includes: nuclear liability coverage; property, decontamination and premature decommissioning coverage; and replacement power expense coverage. The other joint owners of the jointly owned nuclear reactors reimburse USFE&G for certain expenses associated with nuclear insurance per the joint owner agreements. The Price-Anderson Act requires nuclear plant owners to provide for public nuclear liability claims resulting from nuclear incidents to the maximum total financial protection liability, which currently is $12.6 billion. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies — Nuclear Insurance,” for more information.

USFE&G has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate each plant safely. The NCUC, FPSC and the PSCSC require USFE&G regulated utilities to update their cost estimates for decommissioning their nuclear plants every five years.

Duke Energy Carolinas’ most recent site-specific nuclear decommissioning cost studies were completed in 2009 and showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination, of $3 billion in 2008

dollars. This estimate includes Duke Energy Carolinas’ ownership interest in the jointly owned nuclear reactors. The other joint owners of the jointly owned nuclear reactors are responsible for decommissioning costs related to their ownership interests in the station. The balance of Duke Energy Carolinas’ external Nuclear Decommissioning Trust Funds (NDTF) was $2,354 million as of December 31, 2012 and $2,060 million as of December 31, 2011.

Progress Energy Carolinas’ most recent site-specific nuclear decommissioning cost studies were completed in 2009 and showed total estimated nuclear decommissioning costs, including the cost to decommission plant components not subject to radioactive contamination of $3.0 billion in 2009 dollars. This estimate includes Progress Energy Carolinas’ ownership interest in the jointly owned nuclear reactors. The other joint owners of the jointly owned nuclear reactors are responsible for decommissioning costs related to their ownership interests in the station. The balance of Progress Energy Carolinas’ external NDTF was $1,259 million as of December 31, 2012 and $1,088 million as of December 31, 2011.

Progress Energy Florida’s most recent site-specific nuclear decommissioning cost studies were completed in 2008. In the Progress Energy Florida 2009 rate case, the FPSC deferred review of the 2008 nuclear decommissioning study until 2010. While Progress Energy Florida was not required to prepare a new site-specific nuclear decommissioning cost study, it was required to update its 2008 study by incorporating the most currently-available escalation rates.  This update was filed with the FPSC in December 2010. The FPSC approved this study on April 30, 2012 and showed total estimated nuclear decommissioning costs based on prompt dismantlement at the end of Crystal River Unit 3’s useful life , including the cost to decommission plant components not subject to radioactive contamination of $751 million in 2008 dollars. This estimate includes Progress Energy Florida’s ownership interest in the jointly owned nuclear reactor. The other joint owners of the jointly owned nuclear reactor are responsible for decommissioning costs related to their ownership interests in the station. With the decision in early 2013 to retire Crystal River Unit 3, as discussed below, it is anticipated that a delayed dismantlement approach to decommissioning, referred to as SAFSTOR, will be submitted to the NRC for approval. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Once an updated  site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed, including components not subject to radioactive contamination, of $989 million in 2011 dollars. The balance of the external NDTF was $629 million as of December 31, 2012 and $559 million as of December 31, 2011.

The NCUC, FPSC and the PSCSC have allowed USFE&G’s regulated utilities to recover estimated decommissioning costs through retail rates over the expected remaining service periods of their nuclear stations. USFE&G believes that the decommissioning costs being recovered through rates, when coupled with the existing fund balance and expected fund earnings, will be sufficient to provide for the cost of future decommissioning. See Note 9 to the Consolidated Financial Statements, “Asset Retirement Obligations,” for more information.

The Nuclear Waste Policy Act of 1982 (as amended) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Policy Act of 1982 promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. USFE&G will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible.

Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. Progress Energy Carolinas and Progress Energy Florida have contracts with the DOE for the future storage and disposal of our spent nuclear fuel. Delays have occurred in the DOE’s proposed permanent repository to be located at Yucca Mountain, Nevada. See Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” for information about complaints filed by Progress Energy Carolinas and Progress Energy Florida in the United States Court of Federal Claims against the DOE for its failure to fulfill its contractual obligation to receive spent fuel from nuclear plants. Failure to open Yucca Mountain or another facility would leave the DOE open to further claims by utilities.

Until the DOE begins to accept the spent nuclear fuel, Progress Energy Carolinas and Progress Energy Florida will continue to safely manage their spent nuclear fuel. With certain modifications and additional approvals by the NRC, including the installation and/or expansion of on-site dry cask storage facilities at Robinson Nuclear Station (Robinson), Brunswick Nuclear Station (Brunswick) and Crystal River Unit 3 , the Progress Energy Carolinas and Progress Energy Florida’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated by their respective systems through the expiration of the operating licenses, including any license renewals, for their nuclear generating units. Harris has sufficient storage capacity in its spent fuel pools through the expiration of its renewed operating license.

State

The NCUC, the PSCSC, the FPSC, the PUCO, the IURC and the KPSC (collectively, the state utility commissions) approve rates for retail electric service within their respective states. In addition, the PUCO and the KPSC approve rates for retail gas distribution service within their respective states. The state utility commissions, except for the PUCO, also have authority over the construction and operation of USFE&G’s generating facilities. Certificates of Public Convenience and Necessity ( CPCN) issued by the state utility commissions, as applicable, authorize USFE&G to construct and operate its electric facilities, and to sell electricity to retail and wholesale customers. Prior approval from the relevant state utility commission is required for USFE&G’s regulated operating companies to issue securities. The underlying concept of utility ratemaking is to set rates at a level that allows the utility to collect revenues equal to its cost of providing service plus earn a reasonable rate of return on its invested capital, including equity.

Each of the state utility commissions allows recovery of certain costs through various cost-recovery clauses, to the extent the respective commission determines in periodic hearings that such costs, including any past over or under-recovered costs, are prudent. The clauses are in addition to approved base rates. USFE&G’s regulated utilities generally do not earn a return on the recovery of eligible operating expenses under such clauses; however, in certain jurisdictions, they may earn a return on under-recovered costs. Additionally, the commissions may authorize a return for specified investments for energy efficiency and conservation, capacity costs, environmental compliance and utility plant.

Fuel, fuel-related costs and certain purchased power costs are eligible for recovery by USFE&G’s regulated utilities. USFE&G uses coal, oil, hydroelectric, natural gas and nuclear power to generate electricity, thereby maintaining a diverse fuel mix that helps mitigate the impact of cost increases in any one fuel. Due to the associated regulatory treatment and the method allowed for recovery, changes in fuel costs from year to year have no material impact on operating results of USFE&G, unless a commission finds a portion of such costs to have been imprudent. However, delays between the expenditure for fuel costs and recovery from ratepayers can adversely impact the timing of cash flow of USFE&G. Progress Energy Florida is obligated to notify the FPSC and permitted to file for a midcourse change to the fuel factor between annual fuel hearings in the event its estimated over- or under-recovery of fuel costs meets or exceeds a threshold of ten percent of estimated total retail fuel revenues and, accordingly, has the ability to mitigate the cash flow impacts due to the timing of recovery of fuel and purchased power costs.

The following is a summary of pending retail base rate case proceedings for each of USFE&G’s regulated utilities.

Duke Energy Carolinas 2013 North Carolina Rate Case. On February 4, 2013, Duke Energy Carolinas filed an application with the NCUC for an increase in base rates of approximately $446 million, or an average 9.7% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 53% equity and 47% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization, environmental compliance and the capital additions.

Duke Energy Carolinas expects revised rates, if approved, to go into effect late third quarter of 2013.

Progress Energy Carolinas 2012 North Carolina Rate Case. On October 12, 2012, Progress Energy Carolinas filed an application with the NCUC for an increase in base rates of approximately $387 million, or an average 12% increase in revenues. The request for increase is based upon an 11.25% return on equity and a capital structure of 55% equity and 45% long-term debt. The rate increase is designed primarily to recover the cost of plant modernization and other capital investments in generation, transmission and distribution systems, as well as increased expenditures for nuclear plants and personnel, vegetation management and other operating costs. The rate case includes a corresponding decrease in Progress Energy Carolinas’ energy efficiency and demand side management rider, resulting in a net requested increase of $359 million, or 11% increase in retail revenues.

On February 25, 2013, the North Carolina Public Staff filed with the NCUC a Notice of Settlement in Principle (Settlement Notice). Pursuant to the Settlement Notice between Progress Energy Carolinas and the Public Staff, the parties have agreed to a two year step-in to a total agreed upon net rate increase, with the first year providing for a $151 million, or 4.7% average increase in rates, and the second year providing for rates to be increased by an additional $31 million, or 1.0% average increase in rates.  This second year increase is a result of Progress Energy Carolinas agreeing to delay collection of financing costs on the construction work in progress for the Sutton combined cycle natural gas plant for one year.  The Settlement Notice is based upon a return on equity of 10.2% and a 53% equity component of the capital structure. 

Once filed, the actual settlement agreement will be subject to approval by the NCUC. Progress Energy Carolinas expects revised rates, if approved, to go into effect June 1, 2013.

Duke Energy Ohio 2012 Electric Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in electric distribution rates of approximately $87 million. On average, total electric rates would increase approximately 5.1% under the filing. The rate increase is designed to recover the cost of investments in projects to improve reliability for customers and upgrades to the distribution system. Pursuant to a stipulation in another case, Duke Energy Ohio will continue recovering its costs associated with grid modernization in a separate rider.

Duke Energy Ohio expects revised rates, if approved, to go into effect in the first half of 2013.

Duke Energy Ohio 2012 Natural Gas Rate Case. On July 9, 2012, Duke Energy Ohio filed an application with the PUCO for an increase in natural gas distribution rates of approximately $45 million. On average, total natural gas rates would increase approximately 6.6% under the filing. The rate increase is designed to recover the cost of upgrades to the distribution system, as well as environmental cleanup of manufactured gas plant sites. In addition to the recovery of costs associated with the manufactured gas plants, the rate request includes a proposal for an accelerated service line replacement program and a new rider to recover the associated incremental cost. The filing also requests that the PUCO renew the rider recovery of Duke Energy Ohio’s accelerated main replacement program and grid modernization program.

On January 4, 2013, the PUCO Staff filed a staff report recommending that Duke Energy Ohio only be allowed to recover costs related to manufactured gas plant (MGP) sites which are currently used and useful in the provision of natural gas distribution service. Duke Energy Ohio filed its objection to the staff report on February 4, 2013.

Duke Energy Ohio expects revised rates, if approved, to go into effect in the first half of 2013.

The following is a summary of recently resolved or settled retail base rate case proceedings for each of USFE&G’s regulated utilities.

Progress Energy Florida 2012 FPSC Settlement. On February 22, 2012, the FPSC approved a comprehensive settlement agreement among Progress Energy Florida, the Florida Office of Public Counsel and other consumer advocates. The 2012 FPSC Settlement Agreement will continue through the last billing cycle of December 2016. The agreement addresses three principal matters: (i) Progress Energy Florida’s proposed Levy Nuclear Project cost recovery, (ii) the Crystal River Unit 3 delamination prudence review then pending before the FPSC, and (iii) certain customer rate matters. See Note 4 to the Consolidated Financial Statements, “Regulatory Matters – Rate Related Information,” for additional provisions of the 2012 settlement agreement.

Duke Energy Carolinas 2011 North Carolina Rate Case. On January 27, 2012, the NCUC approved a settlement agreement between Duke Energy Carolinas and the North Carolina Utilities Public Staff (Public Staff). The terms of the agreement include an average 7.2% increase in retail revenues, or approximately $309 million annually beginning in February 2012. The agreement includes a 10.5% return on equity and a capital structure of 53% equity and 47% long-term debt.

On March 28, 2012, the North Carolina Attorney General filed a notice of appeal with the NCUC challenging the rate of return approved in the agreement. On April 17, 2012, the NCUC denied Duke Energy Carolinas’ request to dismiss the notice of appeal. Briefs were filed on August 22, 2012 by the North Carolina Attorney General and the American Association of Retired Persons (AARP) with the North Carolina Supreme Court, which is hearing the appeal. Duke Energy Carolinas filed a motion to dismiss the appeal on August 31, 2012 and the North Carolina Attorney General filed a response to that motion on September 13, 2012. Briefs by the appellees, Duke Energy Carolinas and the Public Staff, were filed on September 21, 2012. The North Carolina Supreme Court denied Duke Energy Carolinas’ motion to dismiss on procedural grounds and set the matter for oral arguments on November 13, 2012. Duke Energy Carolinas is awaiting an order.

Duke Energy Carolinas 2011 South Carolina Rate Case. On January 25, 2012, the PSCSC approved a settlement agreement between Duke Energy Carolinas and the ORS, Wal-Mart Stores East, LP, and Sam’s East, Inc. The Commission of Public Works for the city of Spartanburg, South Carolina and the Spartanburg Sanitary Sewer District were not parties to the agreement; however, they did not object to the agreement. The terms of the agreement include an average 5.98% increase in retail and commercial revenues, or approximately $93 million annually beginning February 6, 2012. The agreement includes a 10.5% return on equity, a capital structure of 53% equity and 47% long-term debt.

Duke Energy Ohio Standard Service Offer (SSO). The PUCO approved Duke Energy Ohio’s current Electric Security Plan (ESP) on November 22, 2011. The ESP effectively separates the generation of electricity from Duke Energy Ohio’s retail load obligation and requires Duke Energy Ohio to transfer its generation assets to a nonregulated affiliate on or before December 31, 2014. The ESP includes competitive auctions for electricity supply whereby the energy price is recovered from retail customers. As a result, Duke Energy Ohio now earns retail margin on the transmission and distribution of electricity only and not on the cost of the underlying energy. New rates for Duke Energy Ohio went into effect for SSO customers on January 1, 2012. The ESP also includes a provision for a non-bypassable stability charge of $110 million per year to be collected from January 1, 2012 through December 31, 2014.

On January 18, 2012, the PUCO denied a request for rehearing of its decision on Duke Energy Ohio’s ESP filed by Columbus Southern Power and Ohio Power Company.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters — Rate Related Information.”

Federal

The FERC approves USFE&G’s cost-based rates for electric sales to certain wholesale customers, as well as sales of transmission service. Regulations of FERC and the state utility commissions govern access to regulated electric and gas customers and other data by nonregulated entities and services provided between regulated and nonregulated energy affiliates. These regulations affect the activities of nonregulated affiliates with USFE&G.

Regional Transmission Organizations (RTO). PJM Interconnection, LLC (PJM) and Midwest Independent Transmission System Operator, Inc. (MISO) are the Independent System Operators (ISO) and the FERC-approved RTOs for the regions in which Duke Energy Ohio and Duke Energy Indiana operate. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the PJM region. MISO is the transmission provider under, and the administrator of, the MISO Open Access Transmission Tariff (MISO Tariff), operates the MISO energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the MISO region. Duke Energy Ohio is a member of PJM and provides regional transmission service pursuant to the PJM Tariff. Duke Energy Ohio and the other transmission owners in PJM have turned over control of their transmission facilities to PJM, and their transmission systems are currently under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service. Duke Energy Indiana is a member of MISO and provides regional transmission service pursuant to the MISO Tariff. Duke Energy Indiana and the other transmission owners in MISO have turned over control of their transmission facilities to MISO, and their transmission systems are currently under the dispatch control of MISO. Under the MISO Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the MISO members at rates based on the costs of transmission service.

Prior to January 1, 2012, Duke Energy Ohio was a member of MISO. See Note 4 to the Consolidated Financial Statements, Regulatory Matters, for additional information related to Duke Energy Ohio’s RTO realignment from MISO to PJM.

Other

Nuclear Matters. The nuclear power industry faces uncertainties with respect to the cost and long-term availability of disposal sites for spent nuclear fuel and other radioactive waste, compliance with changing regulatory requirements, capital outlays for modifications and new plant construction, the technological and financial aspects of decommissioning plants at the end of their licensed lives, and requirements relating to nuclear insurance. Nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs, uprates and certain other modifications.

USFE&G is subject to the jurisdiction of the NRC for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy Carolinas’ three Oconee nuclear units through 2033 for Units 1 and 2 and through 2034 for Unit 3. In 2003, the NRC renewed the operating licenses for all units at Duke Energy Carolinas’ McGuire Nuclear Station (McGuire) and Catawba Nuclear Station (Catawba). The two McGuire units are licensed through 2041 and 2043, respectively, while the two Catawba units are licensed through 2043. The NRC has renewed the operating licenses for all of Progress Energy Carolinas’ nuclear plants. The renewed operating licenses for Brunswick Unit 1 and Unit 2, Harris and Robinson expire in 2036, 2034, 2046 and 2030, respectively.

The NRC issues orders with regard to security at nuclear plants in response to new or emerging threats. The most recent orders include additional restrictions on nuclear plant access, increased security measures at nuclear facilities and closer coordination with our partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. USFE&G is in compliance with the requirements outlined in the orders through the use of additional security measures until permanent construction projects are completed in 2013. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required.

Crystal River Unit 3. In September 2009, Crystal River Unit 3 began an outage for normal refueling and maintenance as well as an uprate project to increase its generating capability and to replace two steam generators. During preparations to replace the steam generators, workers discovered a delamination (or separation) within the concrete at the periphery of the containment building, which resulted in an extension of the outage. After analysis, it was determined that the concrete delamination at Crystal River Unit 3 was caused by redistribution of stresses in the containment wall that occurred when an opening was created to accommodate the replacement of the unit’s steam generators. In March 2011, the work to return the plant to service was suspended after monitoring equipment identified a new delamination that occurred in a different section of the outer wall after the repair work was completed and during the late stages of retensioning the containment building. Crystal River Unit 3 has remained out of service while Progress Energy Florida conducted an engineering analysis and review of the new delamination and evaluated possible repair options.

Subsequent to March 2011, monitoring equipment has detected additional changes and further damage in the partially tensioned containment building and additional cracking or delaminations could occur.

Progress Energy Florida developed a repair plan, which would entail systematically removing and replacing concrete in substantial portions of the containment structure walls, which had a preliminary cost estimate of $900 million to $1.3 billion. 

In March 2012, Duke Energy commissioned an independent review team led by Zapata Incorporated (Zapata) to review and assess the Progress Energy Florida Crystal River Unit 3 repair plan, including the repair scope, risks, costs and schedule. In its final report in late September, Zapata found that the proposed repair scope appears to be technically feasible, but there were significant risks that need to be addressed regarding the approach, construction methodology, scheduling and licensing. Zapata performed four separate analyses of the estimated project cost and schedule to repair Crystal River Unit 3, including; (i) an independent review of the proposed repair scope (without existing assumptions or data), of which Zapata estimated costs of $1.49 billion with a project duration of 35 months; (ii) a review of Progress Energy Florida’s previous bid information, which included cost estimate data from Progress Energy Florida, of which Zapata estimated costs of $1.55 billion with a project duration of 31 months; (iii) an expanded scope of work scenario, that included the Progress Energy Florida scope plus the replacement of the containment building dome and the removal and replacement of concrete in the lower building elevations, of which Zapata estimated costs of approximately $2.44 billion with a project duration of 60 months, and; (iv) a “worst case” scenario, assuming Progress Energy Florida performed the more limited scope of work, and at the conclusion of that work, additional damage occurred in the dome and in the lower elevations, which forced replacement of each, of which Zapata estimated costs of $3.43 billion with a project duration of 96 months. The principal difference between Zapata’s estimate and Progress Energy Florida’s previous estimate appears to be due to the respective levels of contingencies included by each party, including higher project risk and longer project duration. Progress Energy Florida has filed a copy of the Zapata report with the FPSC and with the NRC. The FPSC held a status conference on October 30, 2012 to discuss Duke Energy’s analysis of the Zapata report.

On February 5, 2013, following the completion of a comprehensive analysis, Duke Energy announced its intention to retire Crystal River Unit 3. Duke Energy concluded that it did not have a high degree of confidence that repair could be successfully completed and licensed within estimated costs and schedule, and that it was in the best interests of Progress Energy Florida’s customers and joint owners and Duke Energy’s investors to retire the unit. Progress Energy Florida developed initial estimates of the cost to decommission the plant during its analysis of whether to repair or retire Crystal River Unit 3. With the final decision to retire, Progress Energy Florida is working to develop a comprehensive decommissioning plan, which will evaluate various decommissioning options and costs associated with each option. The plan will determine resource needs as well as the scope, schedule and other elements of decommissioning. Progress Energy Florida intends to use a safe storage (SAFSTOR) option for decommissioning. Generally, SAFSTOR involves placing the facility into a safe storage configuration, requiring limited staffing to monitor plant conditions, until the eventual dismantling and decontamination activities occur, usually in 40 to 60 years. This decommissioning approach is currently utilized at a number of retired domestic nuclear power plants and is one of three generally accepted approaches to decommissioning required by the NRC. Once an updated site specific decommissioning study is completed it will be filed with the FPSC. As part of the evaluation of repairing Crystal River Unit 3, initial estimates of the cost to decommission the plant under the SAFSTOR option were developed which resulted in an estimate in 2011 dollars of $989 million. See Note 9 for additional information. Additional specifics about the decommissioning plan are being developed.

Progress Energy Florida maintains insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at Crystal River Unit 3 through NEIL. NEIL provides insurance coverage for repair costs for covered events, as well as the cost of replacement power of up to $490 million per event when the unit is out of service as a result of these events. Actual replacement power costs have exceeded the insurance coverage. Progress Energy Florida also maintains insurance coverage through NEIL’s accidental property damage program, which provides insurance coverage up to $2.25 billion with a $10 million deductible per claim.

Throughout the duration of the Crystal River Unit 3 outage, Progress Energy Florida worked with NEIL for recovery of applicable repair costs and associated replacement power costs. NEIL has made payments on the first delamination; however, NEIL has withheld payment of approximately $70 million of replacement power cost claims and repair cost claims related to the first delamination event. NEIL had not provided a written coverage decision for either delamination and no payments were made on the second delamination and no replacement power reimbursements were made by NEIL since May 2011. These considerations led Progress Energy Florida to conclude, in the second quarter of 2012, that it was not probable that NEIL would voluntarily pay the full coverage amounts that Progress Energy Florida believes them to owe under the applicable insurance policies. Consistent with the terms and procedures under the insurance coverage with NEIL, Progress Energy Florida agreed to non-binding mediation prior to commencing any formal dispute resolution. On February 5, 2013, Progress Energy Florida announced it and NEIL had accepted the mediator’s proposal whereby NEIL will pay Progress Energy Florida an additional $530 million. Along with the $305 million which NEIL previously paid, Progress Energy Florida will receive a total of $835 million in insurance proceeds.

As a result of the 2012 FPSC Settlement Agreement, Progress Energy Florida will be permitted to recover prudently incurred fuel and purchased power costs through its fuel clause without regard for the absence of Crystal River Unit 3 for the period from the beginning of the Crystal River Unit 3 outage through December 31, 2016.

In accordance with the terms of the 2012 FPSC Settlement Agreement, with consumer representatives and approved by the FPSC, Progress Energy Florida retained the sole discretion to retire Crystal River Unit 3. Progress Energy Florida expects that the FPSC will review the prudence of the retirement decision in Phase 2 of the Crystal River Unit 3 delamination regulatory docket. Progress Energy Florida has also asked the FPSC to review the mediated resolution of insurance claims with NEIL as part of Phase 3 of this regulatory docket. Phase 2 and Phase 3 hearings have been tentatively scheduled to begin on June 19, 2013.

 Progress Energy Florida did not begin the repair of Crystal River Unit 3 prior to December 31, 2012. Consistent with the 2012 FPSC Settlement Agreement regarding the timing of commencement of repairs, Progress Energy Florida recorded a Regulatory liability of $100 million in the third quarter of 2012 related to replacement power obligations. This amount is included within fuel used in electric generation and purchased power in Progress Energy Florida’s and Progress Energy’s Statements of Operations and Comprehensive Income for the year ended December 31, 2012. Progress Energy Florida will refund this replacement power liability on a pro rata basis based on the in-service date of up to $40 million in 2015 and $60 million in 2016. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy’s Consolidated Financial Statements.

Progress Energy Florida also retained sole discretion to retire the unit without challenge from the parties to the agreement. As a result, Progress Energy Florida will be allowed to recover all remaining Crystal River Unit 3 investments and to earn a return on the Crystal River Unit 3 investments set at its current authorized overall cost of capital, adjusted to reflect a return on equity set at 70 percent of the current FPSC authorized return on equity, no earlier than the first billing cycle of January 2017.

In conjunction with the decision to retire Crystal River Unit 3, Progress Energy Florida reclassified all Crystal River Unit 3 investments, including property, plant and equipment; nuclear fuel; inventory; and deferred assets to a regulatory asset account. At December 31, 2012, Progress Energy Florida had $1,637 million of net investment in Crystal River Unit 3 recorded in Regulatory assets on its Consolidated Balance Sheets. Progress Energy Florida recorded $192 million of impairment and other charges related to the wholesale portion of Crystal River Unit 3 investments, which are not covered by the 2012 FSPC Settlement Agreement, and other provisions. The significant majority of this amount is recorded in Impairment charges on Progress Energy Florida’s and Progress Energy’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012. This amount is reflected as part of the purchase price allocation of the merger with Progress Energy in Duke Energy’s Consolidated Financial Statements.

In accordance with the 2012 FPSC Settlement Agreement, NEIL proceeds received allocable to retail customers will be applied first to replacement power costs incurred after December 31, 2012 through December 31, 2016, with the remainder used to write down the remaining Crystal River Unit 3 investments.

Progress Energy Florida believes the decision to retire Crystal River Unit 3, the actions taken and costs incurred in response to the Crystal River Unit 3 delamination have been prudent and, accordingly, considers replacement power and capital costs not recoverable through insurance to be recoverable through its fuel cost-recovery clause or base rates. Additional replacement power costs and exit cost to wind down the operations at the plant and decommission Crystal River Unit 3 could be material. Retirement of the plant could impact funding obligations associated with Progress Energy Florida’s nuclear decommissioning trust fund.

Progress Energy Florida is a party to a master participation agreement and other related agreements with the joint owners of Crystal River Unit 3 which convey certain rights and obligations on Progress Energy Florida and the joint owners. In December 2012, Progress Energy Florida reached an agreement with one group of joint owners related to all Crystal River Unit 3 matters.

Progress Energy Florida cannot predict the outcome of matters described above.

Hydroelectric Generating Facilities. All but one of USFE&G’s hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act. The FERC has jurisdiction to issue new hydroelectric operating licenses when the existing license expires. The 13 hydroelectric stations of the Catawba-Wateree Project are in the late stages of the FERC relicensing process. These stations continue to operate under annual extensions of the current FERC license, which expired in 2008, until the FERC issues a new license, which is currently projected to be issued by mid-2013. Relicensing is now under way for two hydroelectric stations comprising the Keowee-Toxaway Project. The current Keowee-Toxaway Project license does not expire until 2016 and the project will continue to operate under the current license until the new license is issued. The Bad Creek Project license will expire in 2028, the Gaston Shoals Project and Ninety Nine Islands Project licenses will expire in 2036 and the Queens Creek Project which will expire in 2023. All other hydroelectric stations are operating under current operating licenses, including ten hydroelectric stations in the East Fork, West Fork, Nantahala, Bryson, Mission, Franklin projects, and the Markland Project (in Indiana) for which new licenses were issued in 2010 through 2012. Duke Energy requested and the FERC approved a license surrender for the Dillsboro project. Duke Energy Carolinas has removed the Dillsboro Project dam and powerhouse as part of multi-project and multi-stakeholder agreements and Duke Energy Carolinas is continuing with stream restoration and post-removal monitoring as requested by FERC’s license surrender order.

Progress Energy Carolinas has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. Progress Energy Carolinas also owns the Marshall Plant, which has a license exemption. The total summer generating capacity for all four units is 225 MW. Progress Energy Carolinas submitted an application to relicense its Tillery and Blewett plants for 50 years and anticipates a decision by the FERC in 2013. The Walters Plant license will expire in 2034.

Other Matters. USFE&G is subject to the jurisdiction of the U.S. Environmental Protection Agency (EPA) and state and local environmental agencies. For a discussion of environmental regulation, see “Environmental Matters” in this section.

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and other EPA regulations under development and the potential impacts such legislation and regulation could have on Duke Energy’s operations.

Commercial Power owns, operates and manages power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power’s generation operations, excluding renewable energy generation assets, consist primarily of coal-fired and gas-fired nonregulated generation assets which are dispatched into wholesale markets. These assets are comprised of 6,825 net MW of power generation primarily located in the Midwestern U.S. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. The coal-fired generation assets were dedicated under the Duke Energy Ohio Electric Security Plan (ESP) through December 31, 2011. As discussed in the USFE&G section above, the new ESP effectively separates the generation of electricity from Duke Energy Ohio’s retail load obligation as of January 1, 2012. As a result, As a result, the energy from Duke Energy Ohio’s coal-fired generation assets no longer serve retail load customers or receive negotiated pricing under the ESP. Effective January 1, 2012, Duke Energy Ohio completed its Regional Transmission Organization (RTO) realignment to PJM and operates as a Fixed Resource Requirement (FRR) entity through May 31, 2015. As an FRR entity, Duke Energy Ohio is obligated to self supply capacity for the Duke Energy Ohio load zone. The generation assets began selling all of their electricity into wholesale markets in January 2012 and currently receive wholesale energy margins and capacity revenues from PJM at market rates. Commercial Power has economically hedged its forecasted coal-fired generation and a significant portion of its forecasted gas-fired generation for 2013. Capacity revenues are 100% contracted in PJM through May 2016.

For information on Commercial Power’s generation facilities, see “Commercial Power” in Item 2, “Properties”

Commercial Power also has a retail sales subsidiary, Duke Energy Retail Sales, LLC (Duke Energy Retail), which is certified by the PUCO as a Competitive Retail Electric Supplier (CRES) provider in Ohio. Duke Energy Retail serves retail electric and gas customers in southwest, west central and northern Ohio with energy and other energy services at competitive rates.

Through Duke Energy Generation Services, Inc. (DEGS), Commercial Power engages in the development, construction and operation of renewable energy projects. In addition, DEGS develops commercial transmission projects. Currently, DEGS has approximately 1,269 net MW of renewable generating capacity in operation as of December 31, 2012.

Duke Energy Ohio Capacity Rider Filing. On August 29, 2012, Duke Energy Ohio filed an application with the PUCO for the establishment of a charge, pursuant to Ohio’s state compensation mechanism, for capacity provided consistent with its obligations as an FRR entity. The application included a request for deferral authority and for a new tariff to implement the charge. The deferral being sought is the difference between its costs and market-based prices for capacity. The requested tariff would implement a charge to be collected via a rider through which such deferred balances will subsequently be recovered. 24 parties moved to intervene. Hearings have been set for April 2, 2013. Duke Energy Ohio expects an order in 2013.

Other Matters. As discussed in the USFE&G section above, the PUCO approved Duke Energy Ohio’s new ESP in November 2011. In November 2011, as a result of changes resulting from the PUCO’s approval of the new ESP, Commercial Power ceased applying regulatory accounting treatment to its Ohio operations. Currently, no portion of Commercial Power applies regulatory accounting.

Commercial Power’s Ohio retail load operations’ rates were subject to approval by the PUCO through December 2011, and thus these operations, through December 31, 2011, are referred to herein as Commercial Power’s regulated operations.

For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters — Rate Related Information.”

Commercial Power is subject to regulation at the federal level, primarily from the FERC. Regulations of the FERC govern access to regulated electric customer and other data by nonregulated entities, and services provided between regulated and non-regulated energy affiliates. These regulations affect the activities of Commercial Power.

Commercial Power is subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on Duke Energy’s operations.

Commercial Power competes for wholesale contracts for the purchase and sale of electricity, coal, natural gas and emission allowances. The market price of commodities and services, along with the quality and reliability of services provided, drive competition in the energy marketing business. Commercial Power’s main competitors include other nonregulated generators in the Midwestern U.S., wholesale power providers, coal and natural gas suppliers, and renewable energy.

Commercial Power relies on coal and natural gas for its generation of electric energy.

Coal. Commercial Power meets its coal demand through a portfolio of purchase supply contracts and spot agreements. Large amounts of coal are purchased under supply contracts with mining operators who mine both underground and at the surface. Commercial Power uses spot-market purchases to meet coal requirements not met by supply contracts. Expiration dates for its supply contracts, which have various price adjustment provisions and market re-openers, range through 2018. Commercial Power expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required as existing contracts expire, though prices will fluctuate over time as coal markets change. The majority of Commercial Power’s coal is sourced from mines in the Northern Appalachian and Illinois basins. Commercial Power has an adequate supply of coal to fuel its projected 2013 operations. The majority of Commercial Power’s coal-fired generation is equipped with flue gas desulfurization equipment. As a result, Commercial Power is able to satisfy the current emission limitations for SO ₂ for existing facilities.

Gas. Commercial Power is responsible for the purchase and the subsequent delivery of natural gas to its gas turbine generators. In general Commercial Power hedges its natural gas requirements using financial contracts. Physical gas is purchased in the spot market to meet generation needs.

International Energy principally operates and manages power generation facilities and engages in sales and marketing of electric power, natural gas, and natural gas liquids outside the U.S. It conducts operations through DEI and its affiliates and its activities principally target power generation in Latin America. Additionally, International Energy owns a 25% interest in National Methanol Company (NMC), a large regional producer of methanol and methyl tertiary butyl ether (MTBE) located in Saudi Arabia. The investment in NMC is accounted for under the equity method of accounting. In the first quarter of 2012, Duke Energy completed the sale of International Energy’s indirect 25% ownership interest in Attiki Gas Supply, S.A (Attiki), a Greek corporation, to an existing equity owner in a series of transactions that resulted in the full discharge of the related debt obligation. See Note 13 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates” for additional information. In 2012, International Energy acquired a 240 MW thermal plant in southern Chile.  In addition, International acquired Iberoamericana de Energía Ibener S.A., which owns and operates a 140 MW hydro complex. See Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions of Businesses and Sales of Other Assets,” for additional information.

International Energy’s customers include retail distributors, electric utilities, independent power producers, marketers and industrial/commercial companies. International Energy’s current strategy is focused on optimizing the value of its current Latin American portfolio and expanding the portfolio through investment in generation opportunities in Latin America.

International Energy owns, operates or has substantial interests in approximately 4,900 gross MW of generation facilities. For information on International Energy’s generation facilities, see “International Energy” in Item 2, “Properties.”

International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government-owned electric generating companies, local distribution companies with self-generation capability and other privately owned electric generating and marketing companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.

A high percentage of International Energy’s portfolio consists of baseload hydroelectric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather, additional generation capacities and other factors affect the supply and demand for electricity in the regions served by International Energy.

Recent legislation in Brazil allowed the renewal of certain concessions that were granted prior to 1995 and due to expire in 2015 to 2017, if, among other things, the concession holders dedicated their generation capacity to the regulated market. International Energy’s concessions, which were granted after 1995, were not affected by this legislation. The change in market prices, if any, from this legislation is not expected to have a significant impact on International Energy’s earnings and cash flows because its generation capacity is highly contracted through 2016.

International Energy’s operations are subject to both country-specific and international laws and regulations. (See “Environmental Matters” in this section.)

The remainder of Duke Energy’s operations is presented as Other. While it is not an operating segment, Other primarily includes unallocated corporate interest expense, certain unallocated corporate costs, Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, contributions to the Duke Energy Foundation, Duke Energy’s effective 50% interest in DukeNet Communications, LLC (DukeNet) and related telecom businesses, and Duke Energy’s effective 60% interest in Duke Energy Trading and Marketing, LLC (DETM), which management is currently in the process of winding down.

Bison’s principal activities as a captive insurance entity include the indemnification of various business risks and losses, such as property, business interruption, workers’ compensation and general liability of subsidiaries and affiliates of Duke Energy. DukeNet develops, owns and operates a fiber optic communications network, primarily in the southeast U.S., serving wireless, local and long-distance communications companies, Internet service providers and other businesses and organizations.

Certain entities within Other are subject to the jurisdiction of state and local agencies.

For a discussion of Duke Energy’s foreign operations see “Management’s Discussion and Analysis of Results of Operations” and Note 3 to the Consolidated Financial Statements, “Business Segments.”

On December 31, 2012, Duke Energy had 27,885 employees. A total of 5,784 operating and maintenance employees were represented by unions.

Executive officers serve until their successors are duly elected or appointed.

There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.

The Duke Energy Registrants are subject to federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Duke Energy is also subject to international laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental laws and regulations affecting the Duke Energy Registrants include, but are not limited to:

·           The Clean Air Act (CAA), as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emission sources are responsible for obtaining permits and for annual compliance and reporting.

·           The Clean Water Act which requires permits for facilities that discharge wastewaters into the environment.

·           The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that currently owns or in the past may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to a disposal site, to share in remediation costs.

·           The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.

·           The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals.

See “Other Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion about potential Global Climate Change legislation and the potential impacts such legislation could have on the Duke Energy Registrants’ operations. Additionally, other recently passed and potential future environmental laws and regulations could have a significant impact on the Duke Energy Registrants’ results of operations, cash flows or financial position. However, if and when such laws and regulations become effective, the Duke Energy Registrants will seek appropriate regulatory recovery of costs to comply within its regulated operations.

For more information on environmental matters involving the Duke Energy Registrants, including possible liability and capital costs, see Notes 4 and 5 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively. Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 5 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with current international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our various business segments and is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of the Duke Energy Registrants.

Duke Energy Carolinas generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. Duke Energy Carolinas is subject to the regulatory provisions of the NCUC, the PSCSC, the NRC and FERC. Duke Energy Carolinas operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Duke Energy Carolinas’ service area covers approximately 24,000 square miles and supplies electric service to 2.4 million residential, commercial and industrial customers. See Item 2. “Properties” for further discussion of Duke Energy Carolinas’ generating facilities, transmission and distribution.

The remainder of Duke Energy Carolinas’ operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its parent, Duke Energy.

Progress Energy, Inc. is a public utility holding company primarily engaged in the regulated electric utility business. Headquartered in Raleigh, North Carolina, it owns, directly or indirectly, all of the outstanding common stock of its utility subsidiaries, Progress Energy Carolinas and Progress Energy Florida. When discussing Progress Energy’s financial information, it necessarily includes the results of Progress Energy Carolinas and Progress Energy Florida.

Progress Energy is subject to the regulatory provisions of the NCUC, the PSCSC, the FPSC, the NRC and the FERC. Progress Energy operates in one reportable segment, Franchised Electric, which generates, transmits, distributes and sells electricity in portions of North Carolina, South Carolina and Florida. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

The remainder of Progress Energy’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its parent, Duke Energy.

Progress Energy Carolinas is a regulated public utility founded in North Carolina in 1908 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. For information about Progress Energy Carolinas’ generating plants, see Item 2, “Properties.” Progress Energy Carolinas is subject to the regulatory provisions of the NCUC, the PSCSC, the NRC and FERC. Progress Energy Carolinas operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Progress Energy Carolinas’ service area covers approximately 34,000 square miles, including a substantial portion of the coastal plain of North Carolina extending from the Piedmont to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in western North Carolina in and around the city of Asheville and an area in the northeastern portion of South Carolina. At December 31, 2012, Progress Energy Carolinas was providing electric services to approximately 1.5 million residential, commercial and industrial customers.

The remainder of Progress Energy Carolinas’ operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

Progress Energy Florida is a regulated public utility founded in Florida in 1899 and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida. For information about Progress Energy Florida’s generating plants, see Item 2, “Properties.” Progress Energy Florida is subject to the regulatory provisions of the FPSC, the NRC and FERC. Progress Energy Florida operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. Substantially all of Franchised Electric operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Progress Energy Florida’s service area covers approximately 20,000 square miles in west-central Florida, and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. Progress Energy Florida is interconnected with 22 municipal and 9 rural electric cooperative systems. At December 31, 2012, Progress Energy Florida was providing electric services to approximately 1.7 million residential, commercial and industrial customers.

The remainder of Progress Energy Florida’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

Duke Energy Ohio is a wholly owned subsidiary of Cinergy, which is a wholly owned subsidiary of Duke Energy. Duke Energy Ohio is a combination electric and gas public utility that provides service in southwestern Ohio and northern Kentucky through its wholly owned subsidiary Duke Energy Kentucky, as well as electric generation in parts of Ohio, Illinois, and Pennsylvania. Duke Energy Ohio’s principal lines of business include generation, transmission and distribution of electricity, the sale of and/or transportation of natural gas, and energy marketing. Duke Energy Kentucky’s principal lines of business include generation, transmission and distribution of electricity, as well as the sale of and/or transportation of natural gas. References herein to Duke Energy Ohio include Duke Energy Ohio and its subsidiaries. Duke Energy Ohio is subject to the regulatory provisions of the PUCO, the KPSC and FERC.

Duke Energy Ohio Business Segments. At December 31, 2012, Duke Energy Ohio operated two business segments, both of which are considered reportable segments under the applicable accounting rules: Franchised Electric and Gas and Commercial Power. For additional information on each of these business segments, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

The following is a brief description of the nature of operations of each of Duke Energy Ohio’s reportable business segments, as well as Other.

Franchised Electric and Gas consists of Duke Energy Ohio’s regulated electric and gas transmission and distribution systems located in Ohio and Kentucky, including its regulated electric generation in Kentucky. Franchised Electric and Gas plans, constructs, operates and maintains Duke Energy Ohio’s transmission and distribution systems, which transmit and distribute electric energy to consumers in southwestern Ohio. In addition, Franchised Electric and Gas plans, constructs, operates and maintains Duke Energy Kentucky’s generation assets and transmission and distribution systems, which generate, transmit and distribute electric energy to consumers in and northern Kentucky. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. Substantially all of Franchised Electric and Gas’ operations are regulated and, accordingly, these operations qualify for regulatory accounting treatment.

Duke Energy Ohio’s Franchised Electric and Gas service area covers 3,000 square miles and supplies electric service to 830,000 residential, commercial and industrial customers and provides regulated transmission and distribution services for natural gas to 500,000 customers. See Item 2. “Properties” for further discussion of Duke Energy Ohio’s Franchised Electric and Gas generating facilities.

Commercial Power owns, operates and manages power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants, as well as other contractual positions. Commercial Power’s generation operations consists primarily of coal-fired generation assets located in Ohio and gas-fired nonregulated generation assets which are dispatched into wholesale markets and receive capacity revenues at market rates. These assets are comprised of 6,825 net MW of power generation primarily located in the Midwestern U.S. The asset portfolio has a diversified fuel mix with baseload and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. The coal-fired generation assets were dedicated under the Duke Energy Ohio ESP through December 31, 2011. Duke Energy Ohio’s Commercial Power reportable operating segment does not include the operations of DEGS or Duke Energy Retail, which is included in the Commercial Power reportable operating segment at Duke Energy. See Item 2. “Properties”, for further discussion of Duke Energy Ohio’s Commercial Power generating facilities.

The PUCO approved Duke Energy Ohio’s new ESP in November 2011. The ESP includes competitive auctions for electricity supply for a term of January 1, 2012 through May 31, 2015. The ESP also includes a provision for a non-bypassable stability charge of $110 million per year to be collected from 2012-2014 and requires Duke Energy Ohio to transfer its generation assets to a nonregulated affiliate on or before December 31, 2014. As a result of the new ESP, the energy from Duke Energy Ohio’s coal-fired generation assets no longer serve retail load customers or receive negotiated pricing under the ESP.

Effective January 1, 2012, Duke Energy Ohio completed its RTO realignment to PJM, and operates as an FRR entity through May 31, 2015. As an FRR entity, Duke Energy Ohio is required to self supply capacity for the Duke Energy Ohio load zone.

See Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” for further discussion related to regulatory filings.

In 2012, 2011, and 2010 Duke Energy Ohio earned approximately 36%, 24%, and 13%, respectively, of its consolidated operating revenues from PJM. These revenues relate to the sale of capacity and electricity from all of Duke Energy Ohio’s nonregulated generation assets in 2012 and its gas-fired nonregulated generation assets in 2011 and 2010.

The remainder of Duke Energy Ohio’s operations is presented as Other. Although it is not considered a business segment, Other primarily consists of certain governance costs allocated by its ultimate parent, Duke Energy.

Duke Energy Indiana, an Indiana corporation organized in 1942, is an indirect wholly owned subsidiary of Duke Energy. Duke Energy Indiana generates, transmits and distributes electricity in central, north central, and southern Indiana. Duke Energy Indiana is subject to the regulatory provisions of the IURC and FERC. Duke Energy Indiana operates one reportable business segment, Franchised Electric, which generates, transmits, distributes and sells electricity. The substantial majority of Duke Energy Indiana’s operations are regulated and qualify for regulatory accounting treatment. For additional information regarding this business segment, including financial information, see Note 3 to the Consolidated Financial Statements, “Business Segments.”

Duke Energy Indiana’s service area covers 23,000 square miles. Duke Energy Indiana supplies electric service to 790,000 residential, commercial and industrial customers. See Item 2. “Properties” for further discussion of Duke Energy Indiana’s generating facilities, transmission and distribution.

The remainder of Duke Energy Indiana’s operations is presented as Other. Although it is not considered a business segment, Other primarily includes certain governance costs allocated by its ultimate parent, Duke Energy.

required environmental regulatory approvals for their operating assets or development projects. Delays in obtaining any required environmental regulatory approvals, failure to obtain and comply with them or changes in environmental laws or regulations to more stringent compliance levels could result in additional costs of operation for existing facilities or development of new facilities being prevented, delayed or subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on the Duke Energy Registrants’ financial position, results of operations or cash flows, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

The EPA has proposed new federal regulations governing the management of coal combustion by-products, including fly ash. These regulations may require the Duke Energy Registrants to make additional capital expenditures and increase operating and maintenance costs.

Other potential new environmental regulations, limiting the use of coal acquired from mountaintop removal and imposing additional requirements on water discharges associated with mountaintop removal, could increase costs of fuel and require the Duke Energy Registrants to make additional related capital expenditures. In addition, the Duke Energy Registrants are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their power generation facilities and natural gas assets acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, the Duke Energy Registrants may obtain, or be required to provide, indemnification against some environmental liabilities. If the Duke Energy Registrants incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, the Duke Energy Registrants could suffer material losses.

The Duke Energy Registrants’ sales may decrease if they are unable to gain adequate, reliable and affordable access to transmission assets.

The Duke Energy Registrants depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver electricity sold to the wholesale market. FERC’s power transmission regulations, as well as those of Duke Energy’s international markets, require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. If transmission is disrupted, or if transmission capacity is inadequate, the Duke Energy Registrants’ ability to sell and deliver products may be hindered.

The different regional power markets have changing regulatory structures, which could affect the Duke Energy Registrants’ growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of the Duke Energy Registrants’ wholesale power marketing business.

The Duke Energy Registrants must meet credit quality standards and there is no assurance that they and their rated subsidiaries will maintain investment grade credit ratings. If the Duke Energy Registrants or their rated subsidiaries are unable to maintain investment grade credit ratings, they would be required under credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect their liquidity.

Each of the Duke Energy Registrants and their rated subsidiaries’ senior unsecured long-term debt is currently rated investment grade by various rating agencies. The Duke Energy Registrants cannot be sure that their senior unsecured long-term debt or that of their rated subsidiaries will be rated investment grade in the future.

If the rating agencies were to rate the Duke Energy Registrants or their rated subsidiaries below investment grade, the entities’ borrowing costs would increase, perhaps significantly. In addition, their potential pool of investors and funding sources would likely decrease. Further, if the Duke Energy Registrants’ short-term debt rating were to fall, access to the commercial paper market could be significantly limited. Any downgrade or other event negatively affecting the credit ratings of the Duke Energy Registrants’ subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase their need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group. A reduction in liquidity and borrowing availability could ultimately impact the ability to indefinitely reinvest the earnings of its international operations, which could result in significant income taxes that would have a material adverse effect on Duke Energy’s results of operations.

A downgrade below investment grade could also require the Duke Energy Registrants to post additional collateral in the form of letters of credit or cash under various credit agreements and trigger termination clauses in some interest rate derivative agreements, which would require cash payments. All of these events would likely reduce the Duke Energy Registrants’ liquidity and profitability and could have a material adverse effect on their financial position, results of operations or cash flows.

The Duke Energy Registrants are exposed to credit risk of the customers and counterparties with whom they do business.

Adverse economic conditions affecting, or financial difficulties of, customers and counterparties with whom the Duke Energy Registrants do business could impair the ability of these customers and counterparties to pay for services or fulfill their contractual obligations, including loss recovery payments under insurance contracts, or cause them to delay such payments or obligations. The Duke Energy Registrants depend on these customers and counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect the Duke Energy Registrants’ cash flows, financial position or results of operations.

The Duke Energy Registrants’ operating results may fluctuate on a seasonal and quarterly basis and can be negatively affected by changes in weather conditions and severe weather.

Electric power generation is generally a seasonal business. In most parts of the U.S., and other markets in which Duke Energy operates, demand for power peaks during the warmer summer months, with market prices typically peaking at that time. In other areas, demand for power peaks during the winter. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. As a result, in the future, the overall operating results of the Duke Energy Registrants’ businesses may fluctuate substantially on a seasonal and quarterly basis and thus make period-to-period comparison less relevant.

Sustained severe drought conditions could impact generation by the Duke Energy Registrants’ hydroelectric plants, as well as their fossil and nuclear plant operations, as these facilities use water for cooling purposes and for the operation of environmental compliance equipment. Furthermore, destruction caused by severe weather events, such as hurricanes, tornadoes, severe thunderstorms, snow and ice storms, can result in lost operating revenues due to outages; property damage, including downed transmission and distribution lines; and additional and unexpected expenses to mitigate storm damage.

The Duke Energy Registrants are involved in numerous legal proceedings, the outcomes of which are uncertain. Adverse resolution of these matters could negatively affect the Duke Energy Registrants’ financial position, results of operations or cash flows.

The Duke Energy Registrants are subject to numerous legal proceedings, including claims for damages for bodily injuries alleged to have arisen prior to 1985 from the exposure to or use of asbestos at electric generation plants of Duke Energy Carolinas. Litigation is subject to many uncertainties and the Duke Energy Registrants cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of

some of the matters could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on the Duke Energy Registrants’ cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require the Duke Energy Registrants to change business practices and procedures, which could also have a material effect on their financial position, results of operations or cash flows.

The Duke Energy Registrants’ results of operations may be negatively affected by overall market, economic and other conditions that are beyond their control.

Sustained downturns or sluggishness in the economy generally affect the markets in which the Duke Energy Registrants operate and negatively influence energy operations. Declines in demand for energy as a result of economic downturns in the Duke Energy Registrants’ franchised electric service territories will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and gas. Although the Duke Energy Registrants’ franchised electric and gas business is subject to regulated allowable rates of return and recovery of certain costs, such as fuel under periodic adjustment clauses, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations. Additionally, prolonged economic downturns that negatively impact the Duke Energy Registrants’ results of operations and cash flows could result in future material impairment charges being recorded to write-down the carrying value of certain assets, including goodwill, to their respective fair values.

The Duke Energy Registrants also sell electricity into the spot market or other competitive power markets on a contractual basis. With respect to such transactions, the Duke Energy Registrants are not guaranteed any rate of return on their capital investments through mandated rates, and revenues and results of operations are likely to depend, in large part, upon prevailing market prices. These market prices may fluctuate substantially over relatively short periods of time and could reduce the Duke Energy Registrants’ revenues and margins and thereby diminish their results of operations.

Factors that could impact sales volumes, generation of electricity and market prices at which the Duke Energy Registrants’ able to sell electricity are as follows:

·        weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, and periods of low rainfall that decrease the Duke Energy Registrants’ ability to operate its facilities in an economical manner;

·        supply of and demand for energy commodities;

·        transmission or transportation constraints or inefficiencies which impact the Duke Energy Registrants’ non-regulated energy operations;

·        availability of competitively priced alternative energy sources, which are preferred by some customers over electricity produced from coal, nuclear or gas plants, and of energy-efficient equipment which reduces energy demand;

·        natural gas, crude oil and refined products production levels and prices;

·        ability to procure satisfactory levels of inventory, such as coal, gas and uranium;

·        electric generation capacity surpluses which cause the Duke Energy Registrants’ non-regulated energy plants to generate and sell less electricity at lower prices and may cause some plants to become non-economical to operate; and

·        capacity and transmission service into, or out of, the Duke Energy Registrants’ markets.

Coal inventory levels have increased due to mild weather, low natural gas and power prices resulting in higher combined cycle gas-fired generation, and the economy’s overall effect on load. Continuation of these factors for an extended period of time could result in additional costs of managing the coal inventory or other costs. If these costs are not recoverable the Duke Energy Registrants’ results of operations could be negatively impacted.

Fluctuations in commodity prices or availability may adversely affect various aspects of the Duke Energy Registrants’ operations as well as their financial condition, results of operations and cash flows.

The Duke Energy Registrants are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, nuclear fuel, electricity and other energy-related commodities, including emission allowances, as a result of their ownership of energy-related assets. Fuel costs are recovered primarily through cost-recovery clauses, subject to the approval of state utility commissions. Additionally, the Duke Energy Registrants have hedging strategies in place to mitigate fluctuations in commodity supply prices, but to the extent that these do not cover the entire exposure to commodity price fluctuations, or their hedging procedures do not work as planned, there can be no assurances that the Duke Energy Registrants’ financial performance will not be negatively impacted by price fluctuations. Additionally, the Duke Energy Registrants are exposed to risk that counterparties will not be able to perform their obligations. Should counterparties fail to perform, the Duke Energy Registrants might be forced to replace the underlying commitment at prevailing market prices possibly resulting in losses in addition to the amounts, if any, already paid to the counterparties.

Certain of the Duke Energy Registrants hedge agreements may result in the receipt of, or posting of, derivative collateral with counterparties, depending on the daily derivative position. Fluctuations in commodity prices that lead to the return of collateral received and/or the posting of collateral with counterparties negatively impact our liquidity. Downgrades in the Duke Energy Registrants’ credit ratings could lead to additional collateral posting requirements. The Duke Energy Registrants continually monitor derivative positions in relation to market price activity.

Poor investment performance of the Duke Energy pension plan holdings and other factors impacting pension plan costs could unfavorably impact the Duke Energy Registrants’ liquidity and results of operations.

The costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and required or voluntary contributions made to the plans. The Subsidiary Registrants participate in employee benefit plans sponsored by Duke Energy or Progress Energy. The Subsidiary Registrants are allocated their proportionate share of the cost and obligations related to these plans. Without sustained growth in the pension investments over time to increase the value of plan assets and depending upon the other factors impacting costs as listed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations, and the Subsidiary Registrants’ proportionate share of such cash funding obligations, could have a material impact on the Duke Energy Registrants’ financial position, results of operations or cash flows.

Potential terrorist activities or military or other actions, including cyber system attacks, could adversely affect the Duke Energy Registrants’ businesses.

The continued threat of terrorism and the impact of retaliatory military and other action by the U.S. and its allies may lead to increased political, economic and financial market instability and volatility in prices for natural gas and oil which may have material adverse affects in ways the Duke Energy

Registrants cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the U.S. and its allies could be directed against companies operating in the U.S. or their international affiliates. Cyber systems, infrastructure and generation facilities such as the Duke Energy Registrants’ nuclear plants could be potential targets of terrorist activities or harmful activities by individuals or groups. The potential for terrorism has subjected the Duke Energy Registrants’ operations to increased risks and could have a material adverse effect on their businesses. In particular, the Duke Energy Registrants may experience increased capital and operating costs to implement increased security for their cyber systems and plants, including nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security, additional security personnel or additional capability following a terrorist incident.

The insurance industry has also been disrupted by these potential events. As a result, the availability of insurance covering risks the Duke Energy Registrants and their competitors typically insure against may decrease. In addition, the insurance the Duke Energy Registrants are able to obtain may have higher deductibles, higher premiums, lower coverage limits and more restrictive policy terms.

Information security risks have generally increased in recent years as a result of the proliferation of new technologies and the increased sophistication and activities of cyber attacks. Through our smart grid and other initiatives, the Duke Energy Registrants have increasingly connected equipment and systems related to the generation, transmission and distribution of electricity to the Internet. Because of the critical nature of the infrastructure and the increased accessibility enabled through connection to the Internet, the Duke Energy Registrants may face a heightened risk of cyber attack. In the event of such an attack, the Duke Energy Registrants could have business operations disrupted, property damaged and customer information stolen; experience substantial loss of revenues, response costs and other financial loss; and be subject to increased regulation, litigation and damage to our reputation.

Additional risks and uncertainties not currently known to the Duke Energy Registrants or which they currently deem to be immaterial also may materially adversely affect the Duke Energy Registrants’ financial condition, results of operations or cash flows.

Failure to attract and retain an appropriately qualified workforce could unfavorably impact the Duke Energy Registrants’ results of operations.

Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base and the lengthy time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If the Duke Energy Registrants are unable to successfully attract and retain an appropriately qualified workforce, their financial position or results of operations could be negatively affected.

The Duke Energy Registrants rely on access to short-term borrowings and longer-term capital markets to finance their capital requirements and support their liquidity needs. Access to those markets can be adversely affected by a number of conditions, many of which are beyond the Duke Energy Registrants’ control.

The Duke Energy Registrants’ businesses are financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from their assets. Accordingly, as a source of liquidity for capital requirements not satisfied by the cash flow from their operations and to fund investments originally financed through debt instruments with disparate maturities, Duke Energy and the Subsidiary Registrants rely on access to short-term money markets as well as longer-term capital markets and the Subsidiary Registrants also rely on access to short-term intercompany borrowings. If the Duke Energy Registrants are not able to access capital at competitive rates or at all, the ability to finance their operations and implement their strategy and business plan as scheduled could be adversely affected. An inability to access capital may limit the Duke Energy Registrants’ ability to pursue improvements or acquisitions that they may otherwise rely on for future growth.

Market disruptions may increase the Duke Energy Registrants’ cost of borrowing or adversely affect their ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity and gas; terrorist attacks or threatened attacks on their facilities or unrelated energy companies; or the overall health of the energy industry. The availability of credit under Duke Energy’s revolving credit facilities depends upon the ability of the banks providing commitments under such facilities to provide funds when their obligations to do so arise. Systematic risk of the banking system and the financial markets could prevent a bank from meeting its obligations under the facility agreement.

Duke Energy maintains revolving credit facilities to provide back-up for a commercial paper program for variable rate demand tax-exempt bonds that may be put to the Duke Energy Registrant issuer at the option of the holder and certain letters of credit at various entities. These facilities typically include borrowing sublimits for the Subsidiary Registrants and financial covenants that limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude Duke Energy from issuing commercial paper or the Duke Energy Registrants from issuing letters of credit or borrowing under the revolving credit facility. Additionally, failure to comply with these financial covenants could result in Duke Energy being required to immediately pay down any outstanding amounts under other revolving credit agreements.

Duke Energy’s investments and projects located outside of the United States expose it to risks related to laws of other countries, taxes, economic conditions, political conditions and policies of foreign governments. These risks may delay or reduce Duke Energy’s realization of value from its international projects.

Duke Energy currently owns and may acquire and/or dispose of material energy-related investments and projects outside the U.S. The economic, regulatory, market and political conditions in some of the countries where Duke Energy has interests or in which it may explore development, acquisition or investment opportunities could present risks related to, among others, Duke Energy’s ability to obtain financing on suitable terms, its customers’ ability to honor their obligations with respect to projects and investments, delays in construction, limitations on its ability to enforce legal rights, and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law, regulations, market rules or tax policy.

Duke Energy’s investments and projects located outside of the United States expose it to risks related to fluctuations in currency rates. These risks, and Duke Energy’s activities to mitigate such risks, may adversely affect its cash flows and results of operations.

Duke Energy’s operations and investments outside the U.S. expose it to risks related to fluctuations in currency rates. As each local currency’s value changes relative to the U.S. dollar — Duke Energy’s principal reporting currency — the value in U.S. dollars of Duke Energy’s assets and liabilities in such locality and the cash flows generated in such locality, expressed in U.S. dollars, also change. Duke Energy’s primary foreign currency rate exposure is to the Brazilian Real.

Duke Energy selectively mitigates some risks associated with foreign currency fluctuations by, among other things, indexing contracts to the U.S. dollar and/or local inflation rates, hedging through debt denominated or issued in the foreign currency and hedging through foreign currency derivatives. These efforts, however, may not be effective and, in some cases, may expose Duke Energy to other risks that could negatively affect its cash flows and results of operations.

Duke Energy’s merger with Progress Energy may not achieve its intended results.

The merger is expected to result in various benefits, including, among other things, cost savings and operating efficiencies relating to the joint dispatch of generation and combining of fuel purchasing power. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including market conditions, risks related to Duke Energy’s businesses, and whether the business of Progress Energy is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs; decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s financial position, results of operations or cash flows.

Duke Energy’s and Progress Energy’s ability to fully utilize tax credits may be limited.

In accordance with the provisions of Internal Revenue Code Section 29/45K, Duke Energy and Progress Energy have generated tax credits based on the content and quantity of coal-based solid synthetic fuels produced and sold to unrelated parties. This tax credit program expired at the end of 2007. The timing of the utilization of the tax credits is dependent upon Duke Energy’s and Progress Energy’s taxable income. The timing of the utilization can also be impacted by certain substantial changes in ownership, including the merger of Duke Energy and Progress Energy. Additionally, in the normal course of business, Duke Energy’s and Progress Energy’s tax returns are audited by the IRS. If Duke Energy’s and Progress Energy’s tax credits were disallowed in whole or in part as a result of an IRS audit, there could be significant additional tax liabilities and associated interest for previously recognized tax credits, which could have a material adverse impact on Duke Energy’s and Progress Energy’s earnings and cash flows. Although Duke Energy and Progress Energy are unaware of any currently proposed legislation or new IRS regulations or interpretations impacting previously recorded synthetic fuels tax credits, the value of credits generated could be unfavorably impacted by such legislation or IRS regulations and interpretations.

Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida may incur substantial costs and liabilities due to their ownership and operation of nuclear generating facilities.

Ownership interest in and operation of nuclear stations by Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida subject them to various risks. These risks include, among other things: the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

Ownership and operation of nuclear generation facilities requires compliance with licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the NRC, which could be prompted by, among other things, events within or outside of Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures, as well as assessments to cover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s results of operations and financial condition.

Ownership and operation of nuclear generation facilities also requires the maintenance of funded trusts that are intended to pay for the decommissioning costs of the respective nuclear power plants. As discussed below, poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s liquidity and results of operations as they could be required to significantly increase their cash contributions to the decommissioning trusts.

Market performance and other changes may decrease the value of Duke Energy Carolinas’, Progress Energy Carolinas’ and Progress Energy Florida’s Nuclear Decommissioning Trust Fund (NDTF) investments, which then could require significant additional funding.

The performance of the capital markets affects the values of the assets held in trust to satisfy future obligations to decommission nuclear plants. Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida have significant obligations in this area and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below projected rates of return. Although a number of factors impact funding requirements, a decline in the market value of the assets may increase the funding requirements of the obligations for decommissioning nuclear plants. If Duke Energy Carolinas, Progress Energy Carolinas and Progress Energy Florida are unable to successfully manage the NDTF assets, their financial condition, results of operations and cash flows could be negatively affected.

The costs of retiring Progress Energy Florida’s Crystal River Unit 3 could prove to be more extensive than is currently identified. All costs associated with retirement of the Crystal River Unit 3 asset, including replacement power, may not be fully recoverable through the regulatory process.

Early retirement could result in continued purchases of replacement power and/or additional capital and operating costs associated with construction of replacement capacity resources to continue to service Progress Energy Florida’s customer needs. However, there is no definitive plan for new generating capacity at this time. In addition, exit costs to wind down operations and ultimately to retire and decommission the plant could exceed estimates and, if not recoverable through the regulatory process, could adversely affect Duke Energy’s, Progress Energy’s and Progress Energy Florida’s financial condition, results of operations and cash flows.

While the foregoing reflects Progress Energy Florida’s current intentions and estimates with respect to the retirement of Crystal River Unit 3, the cost of replacement power, and the degree of recoverability of these costs, are all subject to significant uncertainties. Additional developments with respect to Crystal River Unit 3, costs that are greater than anticipated and recoverability that is less than anticipated could adversely affect Duke Energy’s, Progress Energy’s and Progress Energy Florida’s financial condition, results of operations and cash flows.

Duke Energy Ohio’s and Duke Energy Indiana’s membership in a RTO presents risks that could have a material adverse effect on their results of operations, financial condition and cash flows.

The price at which Duke Energy Ohio can sell its generation capacity and energy is dependent on a number of factors, which include the overall supply and demand of generation and load, other state legislation or regulation, transmission congestion, and its business rules. As a result, the prices in day–ahead and real–time energy markets and RTO capacity markets are subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, are also subject to volatility. PJM Interconnection, LLC (PJM) conducts Reliability Pricing Model (RPM) base residual auctions for capacity on an annual planning year basis. The results of the PJM RPM base residual auction are impacted by the supply and demand of generation and load and also may be impacted by congestion and PJM rules relating to bidding for Demand Response and Energy Efficiency resources. Auction prices could fluctuate substantially over relatively short periods of time. Duke Energy Ohio cannot predict the outcome of future auctions, but if the auction prices are sustained at low levels, its results of operations, financial condition and cash flows could be adversely impacted.

The rules governing the various regional power markets may also change, which could affect Duke Energy Ohio’s and Duke Energy Indiana’s costs and/or revenues. To the degree Duke Energy Ohio and Duke Energy Indiana incur significant additional fees and increased costs to participate in an RTO, their results of operations may be impacted. Duke Energy Ohio and Duke Energy Indiana may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Duke Energy Ohio and Duke Energy Indiana may be required to expand their transmission system according to decisions made by an RTO rather than their own internal planning process. While RTO transmission rates were initially designed to be revenue neutral, various proposals and proceedings currently taking place by the FERC may cause transmission rates to change from time to time. In addition, RTOs has been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on Duke Energy Ohio and Duke Energy Indiana. Duke Energy Ohio and Duke Energy Indiana may also incur fees and costs to participate in RTOs.

As a members of an RTO, Duke Energy Ohio and Duke Energy Indiana are subject to certain additional risks, including those associated with the allocation among RTO members, of losses caused by unreimbursed defaults of other participants in the RTO markets and those associated with complaint cases filed against an RTO that may seek refunds of revenues previously earned by RTO members, including Duke Energy Ohio and Duke Energy Indiana.